-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Ugb+T1R8ugvdBRKhf+BULNB45WubFfKnxdmjArwOg+UEOv/8PRi2K1CTUPJyGx+w gupr6yHtFzXXLY5QGGwzMg== 0001014108-05-000335.txt : 20051102 0001014108-05-000335.hdr.sgml : 20051102 20051102091340 ACCESSION NUMBER: 0001014108-05-000335 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20050930 FILED AS OF DATE: 20051102 DATE AS OF CHANGE: 20051102 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KINDER MORGAN ENERGY PARTNERS L P CENTRAL INDEX KEY: 0000888228 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 760380342 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-11234 FILM NUMBER: 051171536 BUSINESS ADDRESS: STREET 1: 370 VAN GORDON STREET CITY: LAKEWOOD STATE: CO ZIP: 80228 BUSINESS PHONE: 3039144752 MAIL ADDRESS: STREET 1: 370 VAN GORDON STREET STREET 2: 2600 GRAND AVENUE CITY: LAKEWOOD STATE: CO ZIP: 80228-8304 FORMER COMPANY: FORMER CONFORMED NAME: ENRON LIQUIDS PIPELINE L P DATE OF NAME CHANGE: 19970304 10-Q 1 km-form10q_6881230v3.txt QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) F O R M 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2005 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____to_____ Commission file number: 1-11234 KINDER MORGAN ENERGY PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 76-0380342 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 500 Dallas Street, Suite 1000, Houston, Texas 77002 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-369-9000 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X] The Registrant had 154,403,326 common units outstanding as of October 26, 2005. 1
KINDER MORGAN ENERGY PARTNERS, L.P. TABLE OF CONTENTS Page Number PART I. FINANCIAL INFORMATION Item 1: Financial Statements (Unaudited)...................................................................... 3 Consolidated Statements of Income - Three and Nine Months Ended September 30, 2005 and 2004....... 3 Consolidated Balance Sheets - September 30, 2005 and December 31, 2004............................ 4 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2005 and 2004............. 5 Notes to Consolidated Financial Statements........................................................ 6 Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations................. 55 Critical Accounting Policies and Estimates........................................................ 55 Results of Operations............................................................................. 55 Financial Condition............................................................................... 70 Information Regarding Forward-Looking Statements.................................................. 76 Item 3: Quantitative and Qualitative Disclosures About Market Risk............................................ 78 Item 4: Controls and Procedures............................................................................... 78 ` PART II. OTHER INFORMATION Item 1: Legal Proceedings..................................................................................... 79 Item 2: Unregistered Sales of Equity Securities and Use of Proceeds........................................... 79 Item 3: Defaults Upon Senior Securities....................................................................... 79 Item 4: Submission of Matters to a Vote of Security Holders................................................... 79 Item 5: Other Information..................................................................................... 79 Item 6: Exhibits.............................................................................................. 79 Signature............................................................................................. 81
2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Unit Amounts) (Unaudited) Three Months Ended Nine Months Ended September 30 September 30, 2005 2004 2005 2004 --------- --------- ----------- --------- Revenues Natural gas sales............................................ $ 1,975,583 $ 1,485,585 $ 4,820,732 $ 4,261,372 Services..................................................... 470,469 389,794 1,369,496 1,142,215 Product sales and other...................................... 185,202 139,280 539,313 390,510 --------- --------- --------- --------- 2,631,254 2,014,659 6,729,541 5,794,097 --------- --------- --------- --------- Costs and Expenses Gas purchases and other costs of sales....................... 1,970,579 1,475,241 4,795,923 4,231,876 Operations and maintenance................................... 156,486 116,807 448,621 347,396 Fuel and power............................................... 44,951 39,109 132,329 110,621 Depreciation, depletion and amortization..................... 85,356 72,214 258,644 209,623 General and administrative................................... 47,073 37,816 171,058 125,527 Taxes, other than income taxes............................... 28,198 20,636 80,249 59,712 --------- --------- --------- --------- 2,332,643 1,761,823 5,886,824 5,084,755 --------- --------- --------- --------- Operating Income............................................... 298,611 252,836 842,717 709,342 Other Income (Expense) Earnings from equity investments............................. 20,512 20,645 69,422 61,723 Amortization of excess cost of equity investments............ (1,407) (1,394) (4,233) (4,182) Interest, net................................................ (68,348) (46,365) (192,387) (140,178) Other, net................................................... 2,880 149 2,208 403 Minority Interest.............................................. (1,806) (2,789) (6,648) (7,332) --------- --------- --------- --------- Income Before Income Taxes..................................... 250,442 223,082 711,079 619,776 Income Taxes................................................... (5,055) (5,740) (20,245) (15,462) ---------- ---------- ---------- ---------- Net Income..................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314 ========= ========= ========= ========= General Partner's interest in Net Income........................ $ 122,744 $ 100,320 $ 351,724 $ 287,851 Limited Partners' interest in Net Income....................... 122,643 117,022 339,110 316,463 --------- --------- --------- --------- Net Income..................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314 ========= ========= ========= ========= Basic Limited Partners' Net Income per Unit ................... $ 0.58 $ 0.59 $ 1.61 $ 1.62 ========= ========= ========= ========= Diluted Limited Partners' Net Income per Unit ................. $ 0.57 $ 0.59 $ 1.61 $ 1.62 ========= ========= ========= ========= Weighted average number of units used in computation of Limited Partners' Net Income per unit: Basic.......................................................... 213,192 196,854 210,001 195,112 ========= ========= ========= ========= Diluted........................................................ 213,496 196,937 210,199 195,196 ========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands) (Unaudited) September 30, December 31, ASSETS 2005 2004 ---- ---- Current Assets Cash and cash equivalents................................ $ - $ - Restricted deposits...................................... - - Accounts, notes and interest receivable, net Trade................................................. 1,001,060 739,798 Related parties....................................... 5,041 12,482 Inventories Products.............................................. 25,173 17,868 Materials and supplies................................ 12,330 11,345 Gas imbalances Trade................................................. 17,593 24,653 Related parties....................................... - 980 Other current assets..................................... 214,117 46,045 ----------- ----------- 1,275,314 853,171 Property, Plant and Equipment, net......................... 8,693,661 8,168,680 Investments................................................ 410,896 413,255 Notes receivable Trade.................................................... 1,944 1,944 Related parties.......................................... 110,126 111,225 Goodwill................................................... 786,038 732,838 Other intangibles, net..................................... 210,565 15,284 Deferred charges and other assets.......................... 336,105 256,545 ----------- ----------- Total Assets............................................... $11,824,649 $10,552,942 =========== =========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Cash book overdrafts.................................. $ 36,648 $ 29,866 Trade................................................. 917,971 685,034 Related parties....................................... 6,408 16,650 Current portion of long-term debt........................ - - Accrued interest......................................... 39,886 56,930 Accrued taxes............................................ 66,798 26,435 Deferred revenues........................................ 12,876 7,825 Gas imbalances Trade................................................. 24,409 32,452 Related parties....................................... 708 - Accrued other current liabilities........................ 738,134 325,663 ----------- ----------- 1,843,838 1,180,855 Long-Term Liabilities and Deferred Credits Long-term debt Outstanding........................................... 5,187,273 4,722,410 Market value of interest rate swaps................... 115,053 130,153 ------------ ------------ 5,302,326 4,852,563 Deferred revenues........................................ 8,255 14,680 Deferred income taxes.................................... 58,120 56,487 Asset retirement obligations............................. 36,773 37,464 Other long-term liabilities and deferred credits......... 1,030,379 468,727 ----------- ----------- 6,435,853 5,429,921 Commitments and Contingencies (Note 3) Minority Interest.......................................... 40,597 45,646 ----------- ----------- Partners' Capital Common Units............................................. 2,675,823 2,438,011 Class B Units............................................ 113,873 117,414 i-Units.................................................. 1,784,709 1,694,971 General Partner.......................................... 117,558 103,467 Accumulated other comprehensive loss..................... (1,187,602) (457,343) ------------ ------------ 3,504,361 3,896,520 Total Liabilities and Partners' Capital.................... $11,824,649 $10,552,942 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. 4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Increase/(Decrease) in Cash and Cash Equivalents In Thousands) (Unaudited) Nine Months Ended September 30, 2005 2004 -------- --------- Cash Flows From Operating Activities Net income................................................................ $ 690,834 $ 604,314 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization................................. 258,644 209,623 Amortization of excess cost of equity investments........................ 4,233 4,182 Earnings from equity investments......................................... (69,422) (61,723) Distributions from equity investments...................................... 51,552 49,425 Changes in components of working capital, net of effects of acquisitions: Accounts receivable...................................................... (249,056) (41,294) Other current assets..................................................... (394) 27,984 Inventories.............................................................. (7,172) (4,960) Accounts payable......................................................... 222,739 69,811 Accrued liabilities...................................................... (18,275) (43,295) Accrued taxes............................................................ 40,722 33,322 Other, net................................................................. (22,805) (9,519) ----------- ----------- Net Cash Provided by Operating Activities.................................... 901,600 837,870 ---------- ---------- Cash Flows From Investing Activities Acquisitions of assets..................................................... (289,751) (142,534) Additions to property, plant and equip. for expansion and maintenance (597,186) (565,231) projects..................................................................... Sale of investments, property, plant and equipment, net of removal costs... 2,987 859 Contributions to equity investments........................................ (1,202) (7,000) Natural gas stored underground and natural gas liquids line-fill........... (20,208) 219 Other...................................................................... (211) 511 ----------- ---------- Net Cash Used in Investing Activities........................................ (905,571) (713,176) ---------- ---------- Cash Flows From Financing Activities Issuance of debt........................................................... 3,812,933 4,410,926 Payment of debt............................................................ (3,401,190) (4,123,527) Debt issue costs........................................................... (5,723) (2,152) Repayments from (Loans to) related parties................................. - (97,223) Increase in cash book overdrafts........................................... 6,782 -- Proceeds from issuance of common units..................................... 285,407 238,075 Proceeds from issuance of i-units.......................................... - 14,925 Contributions from minority interest....................................... 4,509 3,641 Distributions to partners: Common units............................................................. (337,994) (287,677) Class B units............................................................ (12,115) (11,052) General Partner.......................................................... (337,633) (275,412) Minority interest........................................................ (8,754) (7,221) Other, net................................................................. (2,063) (4,900) ----------- ----------- Net Cash Provided by (Used in) Financing Activities.......................... 4,159 (141,597) ---------- ----------- Effect of exchange rate changes on cash and cash equivalents................. (188) -- ------------ ------------ Increase in Cash and Cash Equivalents........................................ - (16,903) Cash and Cash Equivalents, beginning of period............................... - 23,329 ---------- ---------- Cash and Cash Equivalents, end of period..................................... $ - $ 6,426 =========== ========== Noncash Investing and Financing Activities: Assets acquired by the issuance of units................................... 49,635 -- Assets acquired by the assumption of liabilities........................... 68,045 13,932 The accompanying notes are an integral part of these consolidated financial statements.
5 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. Organization General Unless the context requires otherwise, references to "we," "us," "our" or the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries. We have prepared the accompanying unaudited consolidated financial statements under the rules and regulations of the Securities and Exchange Commission. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America. We believe, however, that our disclosures are adequate to make the information presented not misleading. The consolidated financial statements reflect all adjustments which are solely normal and recurring adjustments that are, in the opinion of our management, necessary for a fair presentation of our financial results for the interim periods. You should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2004. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware corporation, is the sole stockholder of our general partner, Kinder Morgan G.P., Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report. Kinder Morgan Management, LLC, a Delaware limited liability company, was formed on February 14, 2001. Our general partner owns all of Kinder Morgan Management, LLC's voting securities and, pursuant to a delegation of control agreement, our general partner delegated to Kinder Morgan Management, LLC, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that Kinder Morgan Management, LLC cannot take certain specified actions without the approval of our general partner. Under the delegation of control agreement, Kinder Morgan Management, LLC manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, Kinder Morgan Management, LLC's activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries. Kinder Morgan Management, LLC is referred to as "KMR" in this report. Proposed Acquisition On August 1, 2005, KMI and Terasen Inc. announced a definitive agreement whereby KMI will acquire all of the outstanding shares of Terasen Inc., a provider of energy and utility services based in Vancouver, British Columbia, Canada. The total purchase price, including the debt held within the Terasen companies, is expected to be approximately US$5.6 billion. Under the transaction, Terasen shareholders will be able to elect, for each Terasen share held, either (i) C$35.75 in cash, (ii) 0.3331 shares of KMI common stock, or (iii) C$23.25 in cash plus 0.1165 shares of KMI common stock. All elections will be subject to proration in the event total cash elections exceed approximately 65% of the total consideration to be paid or total stock elections exceed approximately 35%. The transaction was unanimously approved by each company's board of directors and by a special committee of independent Terasen directors created by the Terasen board to oversee the process. On October 18, 2005, the transaction was approved by a vote of Terasen shareholders. The transaction is also subject to regulatory approvals and other conditions, and is expected to close by year-end 2005. Terasen owns two core businesses: (i) a natural gas distribution business serving approximately 875,000 customers in British Columbia and (ii) a refined products and crude oil transportation pipeline business with three pipelines, (a) Trans Mountain Pipeline, extending from Edmonton to Vancouver and Washington State, (b) Corridor Pipeline, extending from the Athabasca oilsands to Edmonton and (c) a one-third interest in the Express and Platte pipeline systems extending from Alberta to the U.S. Rocky Mountain and Midwest regions. In addition, Terasen owns a water and utility services business that operates 90 water and wastewater systems in over 50 communities throughout British Columbia, Alberta and Alaska. Income Taxes - Realization of Deferred Tax Assets At December 31, 2004, KMI had a capital loss carryforward of approximately $56.1 million. A capital loss carryforward can be utilized to reduce capital gain during the five years succeeding the year in which a capital loss is incurred. The amounts and the years in which KMI's capital loss carryforward expires are $52.5 million during 2005, $1.6 million during 2006 and $2.0 million during 2008. During the third quarter of 2005, KMI sold its interest in the Wrightsville, Arkansas power facility, generating a capital loss for tax purposes of $68.7 million. For tax purposes, KMI is required to apply its capital gains from the sale of Kinder Morgan Mangement shares to the capital loss from the Wrightsville power facility first, before applying them to its capital loss carryforwards. Our common units and Kinder Morgan Management shares are specific assets that KMI can sell to generate capital gain. KMI sold approximately 2.1 million Kinder Morgan Management shares during the first nine months of 2005, generating a gain for tax purposes of approximately $41.8 million. On October 31, 2005, KMI sold 1,586,965 Kinder Morgan Management shares that it owned, generating a gain for tax purposes of $36.4 million. KMI owned approximately 11.7 million Kinder Morgan Management shares at November 1, 2005. KMI plans to sell additional 6 Kinder Morgan Management shares that it owns to offset the remaining capital loss carryforward of approximately $43 million that expires this year. Basis of Presentation Our consolidated financial statements include our accounts and those of our operating partnerships and their majority-owned and controlled subsidiaries. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior periods have been reclassified to conform to the current presentation. Net Income Per Unit We compute Basic Limited Partners' Net Income per Unit by dividing our limited partners' interest in net income by the weighted average number of units outstanding during the period. Diluted Limited Partners' Net Income per Unit reflects the maximum potential dilution that could occur if units whose issuance depends on the market price of the units at a future date were considered outstanding, or if, by application of the treasury stock method, options to issue units were exercised, both of which would result in the issuance of additional units that would then share in our net income. 2. Acquisitions and Joint Ventures During the first nine months of 2005, we completed or made adjustments for the following acquisitions. Each of the acquisitions was accounted for under the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary allocation of assets and liabilities may be adjusted to reflect the final determined amounts during a period of time following the acquisition. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.
Allocation of Purchase Price ------------------------------------------------------------------- (in millions) ------------------------------------------------------------------- ------------------------------------------------------------------- Ref. Date Acquisition Property Deferred Purchase Current Plant & Charges Minority Price Assets Equipment & Other Goodwill Interest ----- --------------------------------------------------------------- --------- ------------ ---------- -------------------- (1) 1/02 Kinder Morgan Materials Services LLC...... $ 14.4 $0.9 $13.5 $ - $ - $ - (2) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 77.4 22.8 - - (3) 10/04 Kinder Morgan River Terminals LLC......... 89.7 10.3 40.7 16.6 22.1 - (4) 11/04 Charter Products Terminals................ 75.2 3.7 56.5 3.0 13.1 (1.1) (5) 12/04 Kinder Morgan Fairless Hills Terminal..... 7.5 0.3 5.9 1.3 - - (6) 1/05 Claytonville Oil Field Unit .............. 6.5 - 6.5 - - - (7) 4/05 Texas Petcoke Terminal Region ............ 247.4 - 72.4 162.7 12.3 - (8) 7/05 Terminal Assets .......................... 36.2 0.5 35.7 - - - (9) 7/05 General Stevedores, L.P. ................. 8.9 0.6 8.1 0.2 - - (10) 8/05 North Dayton Natural Gas Storage Facility 101.6 - 101.6 - - - erminal Assets .......................... $ (11) 8-9/05 T 4.3 $ 0.4 $3.9 $ - $ - $ -
(1) Kinder Morgan Materials Services LLC Effective January 1, 2002, we acquired all of the equity interests of Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, for an aggregate consideration of $14.4 million, consisting of approximately $11.1 million in cash and the assumption of approximately $3.3 million of liabilities, including long-term debt of $0.4 million. In the first quarter of 2005, we paid $0.3 million to the previous owners for final earn-out provisions pursuant to the purchase and sale agreement. Kinder Morgan Materials Services LLC currently operates approximately 60 transload facilities in 20 states. The facilities handle dry-bulk products, including aggregates, plastics and liquid chemicals. The acquisition of Kinder Morgan Materials Services LLC expanded our growing terminal operations and is part of our Terminals business segment. 7 (2) Kinder Morgan Wink Pipeline, L.P. Effective August 31, 2004, we acquired all of the partnership interests in Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings, L.P. for a purchase price of approximately $100.3 million, consisting of $89.9 million in cash and the assumption of approximately $10.4 million of liabilities, including debt of $9.5 million. In September 2004, we paid the $9.5 million outstanding debt balance. We renamed the limited partnership Kinder Morgan Wink Pipeline, L.P., and since August 31, 2004, we have included its results as part of our CO2 business segment. In the second quarter of 2005, we made our final allocation of purchase price to acquired assets, resulting in offsetting adjustments to intangibles and property, plant and equipment in the amount of $1.0 million. The acquisition included a 450-mile crude oil pipeline system, consisting of four mainline sections, numerous gathering systems and truck off-loading stations. The mainline sections, all in Texas, have a total capacity of 115,000 barrels of crude oil per day. As part of the transaction, we entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western's 107,000 barrel per day refinery in El Paso, Texas. The acquisition allows us to better manage crude oil deliveries from our oil field interests in West Texas. Our allocation of the purchase price to assets acquired and liabilities assumed was based on an independent appraisal of fair market values, which was completed in the second quarter of 2005. The $22.8 million of deferred charges and other assets in the table above represents the fair value of the intangible long-term throughput agreement. (3) Kinder Morgan River Terminals LLC Effective October 6, 2004, we acquired Global Materials Services LLC and its consolidated subsidiaries from Mid-South Terminal Company, L.P. for approximately $89.7 million, consisting of $31.8 million in cash and $57.9 million of assumed liabilities, including debt of $33.7 million. Global Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC, operates a network of 21 river terminals and two rail transloading facilities primarily located along the Mississippi River system. The network provides loading, storage and unloading points for various bulk commodity imports and exports. As of our acquisition date, we expected to invest an additional $9.4 million over the next two years to expand and upgrade the terminals, which are located in 11 Mid-Continent states. The acquisition further expands and diversifies our customer base and complements our existing terminal facilities located along the lower-Mississippi River system. The acquired terminals are included in our Terminals business segment. In the third quarter of 2005, we made purchase price adjustments to the acquired assets based on a preliminary independent appraisal of fair market values, which is expected to be completed in the fourth quarter of 2005. The $22.1 million of goodwill was assigned to our Terminals business segment, and the entire amount is expected to be deductible for tax purposes. The $16.6 million of deferred charges and other assets in the table above includes $12.9 million representing the fair value of intangible customer relationships, which encompass both the contractual life of customer contracts plus any future customer relationship value beyond the contract life. (4) Charter Products Terminals Effective November 5, 2004, we acquired ownership interests in nine refined petroleum products terminals in the southeastern United States from Charter Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2 million, consisting of $72.4 million in cash and $2.8 million of assumed liabilities. Three terminals are located in Selma, North Carolina, and the remaining facilities are located in Greensboro and Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South Carolina. We fully own seven of the terminals and jointly own the remaining two. The nine facilities have a combined 3.2 million barrels of storage. All of the terminals are connected to products pipelines owned by either Plantation Pipe Line Company or Colonial Pipeline Company. The acquisition complements the other terminals we own in the Southeast and increased our southeast terminal storage capacity 76% (to 7.7 million barrels) and terminal throughput capacity 62% (to over 340,000 barrels per day). The acquired terminals are included as part of our Products Pipelines business segment. Our allocation of the purchase price to assets acquired and liabilities assumed was based on a preliminary independent appraisal of fair market values, which is expected to be completed in the fourth quarter of 2005. The $13.1 million of goodwill was assigned to our Products Pipelines business segment and the entire amount is expected to be deductible for tax purposes. 8 (5) Kinder Morgan Fairless Hills Terminal Effective December 1, 2004, we acquired substantially all of the assets used to operate the major port distribution facility located at the Fairless Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located along the Delaware River. It is the largest port on the East Coast for the handling of semi-finished steel slabs, which are used as feedstock by domestic steel mills. The port operations at Fairless Hills also include the handling of other types of steel and specialized cargo that caters to the construction industry and service centers that use steel sheet and plate. In the second quarter of 2005, after completing a final inventory count, we allocated $0.3 million of our purchase price that was originally allocated to property, plant and equipment to current assets (materials and supplies-parts inventory). The terminal acquisition expanded our presence along the Delaware River and complemented our existing Mid-Atlantic terminal facilities. We include its operations in our Terminals business segment. (6) Claytonville Oil Field Unit Effective January 31, 2005, we acquired an approximate 64.5% gross working interest in the Claytonville oil field unit located in Fisher County, Texas from Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in the Permian Basin of West Texas. Our purchase price was approximately $6.5 million, consisting of $6.2 million in cash and the assumption of $0.3 million of liabilities. Following our acquisition, we became the operator of the field, which at the time of acquisition was producing approximately 200 barrels of oil per day. The acquisition of this ownership interest complemented our existing carbon dioxide assets in the Permian Basin, and as of our acquisition date and pending further studies as to the technical and economic feasibility of carbon dioxide injection, we may invest an additional $30 million in the field in order to increase production. The acquired operations are included as part of our CO2 business segment. (7) Texas Petcoke Terminal Region Effective April 29, 2005, we acquired seven bulk terminal operations from Trans-Global Solutions, Inc. for an aggregate consideration of approximately $247.4 million, consisting of $186.1 million in cash, $46.3 million in common units, and an obligation to pay an additional $15 million on April 29, 2007, two years from closing. We will settle the $15 million liability by issuing additional common units. All of the acquired assets are located in the State of Texas, and include facilities at the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship Channel. We combined the acquired operations into a new terminal region called the Texas Petcoke region, as certain of the terminals have contracts in place to provide petroleum coke handling services for major Texas oil refineries. The acquisition complemented our existing Gulf Coast terminal facilities and expanded our pre-existing petroleum coke handling operations. The acquired operations are included as part of our Terminals business segment. Our allocation of the purchase price to assets acquired and liabilities assumed was based on a preliminary independent appraisal of fair market values, which is expected to be completed in the fourth quarter of 2005. The $12.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. The $162.7 million of deferred charges and other assets in the table above represents the fair value of intangible customer relationships, which encompass both the contractual life of customer contracts plus any future customer relationship value beyond the contract life. (8) July 2005 Terminal Assets In July 2005, we acquired three terminal facilities in separate transactions for an aggregate consideration of approximately $36.2 million in cash. For the three terminals combined, as of the acquisition date, we expected to invest approximately $14 million subsequent to acquisition in order to enhance the terminals' operational efficiency. The largest of the transactions was the purchase of a refined petroleum products terminal in New York Harbor from ExxonMobil Oil Corporation. The second acquisition involved a dry-bulk river terminal located in the State of Kentucky, and the third involved a liquids/dry-bulk facility located in Blytheville, Arkansas. The operations of all three facilities are included in our Terminals business segment. 9 The New York Harbor terminal, located on Staten Island and referred to as the Kinder Morgan Staten Island terminal, complemented our existing Northeast liquids terminal facilities located in Carteret and Perth Amboy, New Jersey. At the time of acquisition, the terminal had storage capacity of 2.3 million barrels for gasoline, diesel and fuel oil, and we expect to bring several idle tanks back into service that would add another 550,000 barrels of capacity. In addition, we plan to rebuild a ship berth with the ability to accommodate tanker vessels. As part of the transaction, ExxonMobil has entered into a long-term storage capacity agreement with us and will continue to utilize a portion of the terminal. The dry-bulk terminal, located along the Ohio River in Hawsville, Kentucky, primarily handles wood chips and finished paper products. The acquisition complemented our existing terminal assets located in the Ohio River Valley and further expanded our wood-chip handling businesses. As part of the transaction, we assumed a long-term handling agreement with Weyerhauser Company, an international forest products company, and we plan to expand the terminal in order to increase utilization and provide storage services for additional products. The assets acquired at the liquids/dry-bulk facility in Blytheville, Arkansas consist of storage and supporting infrastructure for 40,000 tons of anhydrous ammonia, 9,500 tons of urea ammonium nitrate solutions and 40,000 tons of urea. As part of the transaction, we have entered into a long-term agreement to sublease all of the existing anhydrous ammonia and urea ammonium nitrate terminal assets to Terra Nitrogen Company, L.P. The terminal is one of only two facilities in the United States that can handle imported fertilizer and provide shipment west on railcars, and the acquisition of the facility has positioned us to take advantage of the increase in fertilizer imports that has resulted from the recent decrease in domestic production. (9) General Stevedores, L.P. Effective July 31, 2005, we acquired all of the partnership interests in General Stevedores, L.P. for an aggregate consideration of approximately $8.9 million, consisting of $2.1 million in cash, $3.4 million in common units, and $3.4 million in assumed liabilities, including debt of $3.0 million. In August 2005, we paid the $3.0 million outstanding debt balance. General Stevedores, L.P. owns, operates and leases barge unloading facilities located along the Houston, Texas ship channel. Its operations primarily consist of receiving, storing and transferring semi-finished steel products, including coils, pipe and billets. The acquisition complemented and further expanded our existing Texas Gulf Coast terminal facilities, and its operations are included as part of our Terminals business segment. Our allocation of the purchase price to assets acquired and liabilities assumed is preliminary, pending final determination of working capital balances at the time of acquisition. We expect these final working capital adjustments to be made in the fourth quarter of 2005. (10) Natural Gas Storage Facility Effective August 1, 2005, we acquired a natural gas storage facility in Liberty County, Texas, from Texas Genco LLC for an aggregate consideration of approximately $101.6 million, consisting of $50.9 million in cash, $49.2 million in assumed debt, and a $1.5 million purchase price liability that will be paid in the fourth quarter of 2005. The facility, referred to as our North Dayton storage facility, has approximately 6.3 billion cubic feet of total capacity, consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of pad (cushion) gas. The acquisition complemented our existing Texas intrastate natural gas pipeline group assets and positioned us to pursue expansions at the facility that will provide needed services to utilities, the growing liquefied natural gas industry along the Texas Gulf Coast, and other natural gas storage users. Additionally, as part of the transaction, we entered into a long-term storage capacity and transportation agreement with Texas Genco, one of the largest wholesale electric power generating companies in the United States, with over 13,000 megawatts of generation capacity. The North Dayton storage facility's operations are included in our Natural Gas Pipelines business segment. (11) August and September 2005 Terminal Assets In August and September 2005, we acquired certain terminal facilities and assets, including both real and personal property, in two separate transactions for an aggregate consideration of approximately $4.3 million in cash. In August 2005, we spent $1.9 million to acquire the Kinder Morgan Blackhawk terminal from White Material Handling, Inc., and in September 2005, we spent $2.4 million to acquire a repair shop and related assets from Trans-Global Solutions, Inc. The Kinder Morgan Blackhawk terminal consists of approximately 46 acres of land, 10 storage buildings, and related equipment located in Black Hawk County, Iowa. The terminal primarily stores and transfers fertilizer and salt and further expands our Midwest region bulk terminal operations. The acquisition of the repair shop, located in Jefferson County, Texas, near Beaumont, consists of real and personal property, including parts inventory. The acquisition facilitated and expanded the earlier acquisition of our Texas Petcoke terminals from Trans-Global Solutions effective April 29, 2005. The operations of both acquisitions are included in our Terminals business segment. Pro Forma Information The following summarized unaudited pro forma consolidated income statement information for the nine months ended September 30, 2005 and 2004, assumes that all of the acquisitions we have made and joint ventures we have entered into since January 1, 2004, including the ones listed above, had occurred as of the beginning of the period presented. We have prepared these unaudited pro forma financial results for comparative purposes only. These unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed these acquisitions and joint ventures as of the beginning of the period presented or the results that will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts:
Pro Forma Nine Months Ended September 30, 2005 2004 ------------- ------------- (Unaudited) Revenues.......................................................... $ 6,762,832 $ 5,968,369 Operating Income.................................................. 855,643 768,816 Net Income........................................................ $ 697,266 $ 654,415 Basic Limited Partners' Net Income per unit....................... $ 1.64 $ 1.84 Diluted Limited Partners' Net Income per unit..................... $ 1.64 $ 1.83
3. Litigation, Environmental and Other Contingencies Federal Energy Regulatory Commission Proceedings SFPP, L.P. SFPP, L.P., referred to in this report as SFPP, is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the FERC, including shippers' complaints regarding interstate rates on our Pacific operations' pipeline systems. OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a consolidated proceeding that began in September 1992 and includes a number of shipper complaints against certain rates and practices on SFPP's East Line (from El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson Station in Carson, California. The complainants in the case are El Paso Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company, Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.), Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco Corporation (now part of ConocoPhillips Company). The FERC has ruled that the complainants have the burden of proof in this proceeding. A FERC administrative law judge held hearings in 1996, and issued an initial decision in September 1997. The initial decision held that all but one of SFPP's West Line rates were "grandfathered" under the Energy Policy Act of 1992 and therefore deemed to be just and reasonable; it further held that complainants had failed to prove "substantially changed circumstances" with respect to those rates and that the rates therefore could not be challenged in the Docket No. OR92-8 et al. proceedings, either for the past or prospectively. However, the initial decision also made rulings generally adverse to SFPP on certain cost of service issues relating to the evaluation of East Line rates, which are not "grandfathered" under the Energy Policy Act. Those issues included the capital structure to be used in computing SFPP's "starting rate base," the level of income tax allowance SFPP may include in rates and the recovery of civil and 11 regulatory litigation expenses and certain pipeline reconditioning costs incurred by SFPP. The initial decision also held SFPP's Watson Station gathering enhancement service was subject to FERC jurisdiction and ordered SFPP to file a tariff for that service. The FERC subsequently reviewed the initial decision, and issued a series of orders in which it adopted certain rulings made by the administrative law judge, changed others and modified a number of its own rulings on rehearing. Those orders began in January 1999, with FERC Opinion No. 435, and continued through June 2003. The FERC affirmed that all but one of SFPP's West Line rates are "grandfathered" and that complainants had failed to satisfy the threshold burden of demonstrating "substantially changed circumstances" necessary to challenge those rates. The FERC further held that the one West Line rate that was not grandfathered did not need to be reduced. The FERC consequently dismissed all complaints against the West Line rates in Docket Nos. OR92-8 et al. without any requirement that SFPP reduce, or pay any reparations for, any West Line rate. The FERC initially modified the initial decision's ruling regarding the capital structure to be used in computing SFPP's "starting rate base" to be more favorable to SFPP, but later reversed that ruling. The FERC also made certain modifications to the calculation of the income tax allowance and other cost of service components, generally to SFPP's disadvantage. On multiple occasions, the FERC required SFPP to file revised East Line rates based on rulings made in the FERC's various orders. SFPP was also directed to submit compliance filings showing the calculation of the revised rates, the potential reparations for each complainant and in some cases potential refunds to shippers. SFPP filed such revised East Line rates and compliance filings in March 1999, July 2000, November 2001 (revised December 2001), October 2002 and February 2003 (revised March 2003). Most of those filings were protested by particular SFPP shippers. The FERC has held that certain of the rates SFPP filed at the FERC's directive should be reduced retroactively and/or be subject to refund; SFPP has challenged the FERC's authority to impose such requirements in this context. While the FERC initially permitted SFPP to recover certain of its litigation, pipeline reconditioning and environmental costs, either through a surcharge on prospective rates or as an offset to potential reparations, it ultimately limited recovery in such a way that SFPP was not able to make any such surcharge or take any such offset. Similarly, the FERC initially ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that party's complaint was filed, but ultimately held that each complainant could recover reparations for a period extending two years prior to the filing of its complaint (except for Navajo, which was limited to one month of pre-complaint reparations under a settlement agreement with SFPP's predecessor). The FERC also ultimately held that SFPP was not required to pay reparations or refunds for Watson Station gathering enhancement fees charged prior to filing a FERC tariff for that service. In April 2003, SFPP paid complainants and other shippers reparations and/or refunds as required by FERC's orders. In August 2003, SFPP paid shippers an additional refund as required by FERC's most recent order in the Docket No. OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003 for reparations and refunds pursuant to a FERC order. Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for review of FERC's Docket OR92-8 et al. orders in the United States Court of Appeals for the District of Columbia Circuit. Certain of those petitions were dismissed by the Court of Appeals as premature, and the remaining petitions were held in abeyance pending completion of agency action. However, in December 2002, the Court of Appeals returned to its active docket all petitions to review the FERC's orders in the case through November 2001 and severed petitions regarding later FERC orders. The severed orders were held in abeyance for later consideration. Briefing in the Court of Appeals was completed in August 2003, and oral argument took place on November 12, 2003. On July 20, 2004, the Court of Appeals issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP, L.P. Among other things, the court's opinion vacated the income tax allowance portion of the FERC opinion and order allowing recovery in SFPP's rates for income taxes and remanded to the FERC this and other matters for further proceedings consistent with the court's opinion. In reviewing a series of FERC 12 orders involving SFPP, the court held, among other things, that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. By its terms, the portion of the opinion addressing SFPP only pertained to SFPP, L.P. and was based on the record in that case. The Court of Appeals held that, in the context of the Docket No. OR92-8, et al. proceedings, all of SFPP's West Line rates were grandfathered other than the charge for use of SFPP's Watson Station gathering enhancement facility and the rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded that the FERC had a reasonable basis for concluding that the addition of a West Line origin point at East Hynes, California did not involve a new "rate" for purposes of the Energy Policy Act. It rejected arguments from West Line Shippers that certain protests and complaints had challenged West Line rates prior to the enactment of the Energy Policy Act. The Court of Appeals also held that complainants had failed to satisfy their burden of demonstrating substantially changed circumstances, and therefore could not challenge grandfathered West Line rates in the Docket No. OR92-8 et al. proceedings. It specifically rejected arguments that other shippers could "piggyback" on the special Energy Policy Act exception permitting Navajo to challenge grandfathered West Line rates, which Navajo had withdrawn under a settlement with SFPP. The court remanded to the FERC the changed circumstances issue "for further consideration" in light of the court's decision regarding SFPP's tax allowance. While, the FERC had previously held in the OR96-2 proceeding (discussed following) that the tax allowance policy should not be used as a stand-alone factor in determining when there have been substantially changed circumstances, the FERC's May 4, 2005 income tax allowance policy statement (discussed following) may affect how the FERC addresses the changed circumstances and other issues remanded by the court. The Court of Appeals upheld the FERC's rulings on most East Line rate issues; however, it found the FERC's reasoning inadequate on some issues, including the tax allowance. The court held the FERC had sufficient evidence to use SFPP's December 1988 stand-alone capital structure to calculate its starting rate base as of June 1985; however, it rejected SFPP arguments that would have resulted in a higher starting rate base. The Court of Appeals accepted the FERC's treatment of regulatory litigation costs, including the limitation of recoverable costs and their offset against "unclaimed reparations" - that is, reparations that could have been awarded to parties that did not seek them. The court also accepted the FERC's denial of any recovery for the costs of civil litigation by East Line shippers against SFPP based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix. However, the court did not find adequate support for the FERC's decision to allocate the limited litigation costs that SFPP was allowed to recover in its rates equally between the East Line and the West Line, and ordered the FERC to explain that decision further on remand. The Court of Appeals held the FERC had failed to justify its decision to deny SFPP any recovery of funds spent to recondition pipe on the East Line, for which SFPP had spent nearly $6 million between 1995 and 1998. It concluded that the Commission's reasoning was inconsistent and incomplete, and remanded for further explanation, noting that "SFPP's shippers are presently enjoying the benefits of what appears to be an expensive pipeline reconditioning program without sharing in any of its costs." The Court of Appeals affirmed the FERC's rulings on reparations in all respects. It held the Arizona Grocery doctrine did not apply to orders requiring SFPP to file "interim" rates, and that "FERC only established a final rate at the completion of the OR92-8 proceedings." It held that the Energy Policy Act did not limit complainants' ability to seek reparations for up to two years prior to the filing of complaints against rates that are not grandfathered. It rejected SFPP's arguments that the FERC should not have used a "test period" to compute reparations that it should have offset years in which there were underrecoveries against those in which there were overrecoveries, and that it should have exercised its discretion against awarding any reparations in this case. The Court of Appeals also rejected: - Navajo's argument that its prior settlement with SFPP's predecessor did not limit its right to seek reparations; 13 - Valero's argument that it should have been permitted to recover reparations in the Docket No. OR92-8 et al. proceedings rather than waiting to seek them, as appropriate, in the Docket No. OR96-2 et al. proceedings; - arguments that the former ARCO and Texaco had challenged East Line rates when they filed a complaint in January 1994 and should therefore be entitled to recover East Line reparations; and - Chevron's argument that its reparations period should begin two years before its September 1992 protest regarding the six-inch line reversal rather than its August 1993 complaint against East Line rates. On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips and ExxonMobil filed a petition for rehearing and rehearing en banc asking the Court of Appeals to reconsider its ruling that West Line rates were not subject to investigation at the time the Energy Policy Act was enacted. On September 3, 2004, SFPP filed a petition for rehearing asking the court to confirm that the FERC has the same discretion to address on remand the income tax allowance issue that administrative agencies normally have when their decisions are set aside by reviewing courts because they have failed to provide a reasoned basis for their conclusions. On October 4, 2004, the Court of Appeals denied both petitions without further comment. On November 2, 2004, the Court of Appeals issued its mandate remanding the Docket No. OR92-8 proceedings to the FERC. SFPP and shipper parties subsequently filed various pleadings with the FERC regarding the proper nature and scope of the remand proceedings. On December 2, 2004, the FERC issued a Notice of Inquiry and opened a new proceeding (Docket No. PL05-5) to consider how broadly the court's ruling on the tax allowance issue in BP West Coast Products, LLC, v. FERC should affect the range of entities the FERC regulates. The FERC sought comments on whether the court's ruling applies only to the specific facts of the SFPP proceeding, or also extends to other capital structures involving partnerships and other forms of ownership. Comments were filed by numerous parties, including our Rocky Mountain natural gas pipelines, in the first quarter of 2005. On May 4, 2005, the FERC adopted a policy statement in Docket No. PL05-5, providing that all entities owning public utility assets - oil and gas pipelines and electric utilities - would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. Any tax pass-through entity seeking an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity's public utility income. The FERC expressed the intent to implement its policy in individual cases as they arise. Subject to that case-specific implementation, the policy appears to provide an opportunity for partnership-owned pipelines to seek allowances based upon their entire income paid to partners, rather than the partial allowance provided under the prior Lakehead approach. We expect the final adoption and implementation by the FERC of the policy statement in individual cases will be subject to review of the United States Court of Appeals for the District of Columbia Circuit. The FERC's June 1, 2005 Order on Remand and Rehearing (discussed following) required further briefing with respect to the SFPP income tax allowance and may result in further proceedings on that issue. On December 17, 2004, the Court of Appeals issued orders directing that the petitions for review relating to FERC orders issued after November 2001, which had previously been severed from the main Court of Appeals docket, should continue to be held in abeyance pending completion of the remand proceedings before the FERC. On January 3, 2005, SFPP filed a petition for a writ of certiorari asking the United States Supreme Court to review the Court of Appeals' ruling that the Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only established a final rate at the completion of the OR92-8 proceedings." BP West Coast Products and ExxonMobil also filed a petition for certiorari, on December 30, 2004, seeking review of the Court of Appeals' ruling that there was no pending investigation of West Line rates at the time of enactment of the Energy Policy Act (and thus that those rates remained grandfathered). On April 6, 2005, the Solicitor General filed a brief in opposition to both petitions on behalf of the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and Western Refining filed an opposition to SFPP's petition. SFPP filed a reply to those briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued orders denying the petitions for certiorari filed by SFPP and by BP West Coast Products and ExxonMobil. On June 1, 2005, the FERC issued its Order on Remand and Rehearing, which addressed issues in both the OR92-8 and OR96-2 proceedings (discussed following). 14 With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on several issues that had been remanded by the Court of Appeals in BP West Coast Products and required further briefing on the income tax allowance issue in light of the FERC's May 4, 2005 policy statement. The FERC held that SFPP's allowable regulatory litigation costs in the OR92-8 proceedings should be allocated between the East Line and the West Line based on the volumes carried by those lines during the relevant period. In doing so, it reversed its prior decision to allocate those costs between the two lines on a 50-50 basis. The FERC affirmed its prior decision to exclude SFPP's pipeline reconditioning costs from the cost of service in the OR92-8 proceedings but stated that SFPP will have an opportunity to justify much of those reconditioning expenses in the OR96-2 proceedings. The FERC held that SFPP's contract charge for use of the Watson Station gathering enhancement facilities was not grandfathered and required further proceedings before an administrative law judge to determine the reasonableness of that charge; those proceedings are currently scheduled to go to hearing in January 2006. However, the FERC deferred further proceedings on the non-grandfathered West Line turbine fuel rate until completion of its review of the initial decision in phase two of the OR96-2 proceedings. With respect to the income tax allowance, the FERC held that its May 4, 2005 policy statement would apply in the OR92-8 and OR96-2 proceedings and that SFPP "should be afforded an income tax allowance on all of its partnership interests to the extent that the owners of those interests had an actual or potential tax liability during the periods at issue." It directed SFPP and opposing parties to file briefs regarding the state of the existing record on those questions and the need for further proceedings. Those filings are described below in the discussion of the OR96-2 proceedings. Petitions for review of the June 1, 2005 order by the United States Court of Appeals for the District of Columbia Circuit have been filed by SFPP, Navajo, Western Refining, BP West Coast Products, ExxonMobil, Chevron, ConocoPhillips, Ultramar and Valero. SFPP has moved to intervene in the review proceedings brought by the other parties. Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipeline (Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject to FERC's jurisdiction under the Interstate Commerce Act, and claimed that the rate for that service was unlawful. Several other West Line shippers filed similar complaints and/or motions to intervene. In an August 1997 order, the FERC held that the movements on the Sepulveda pipeline were subject to its jurisdiction. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda Line at five cents per barrel. Several shippers protested that rate. In December 1997, SFPP filed an application for authority to charge a market-based rate for the Sepulveda service, which application was protested by several parties. On September 30, 1998, the FERC issued an order finding that SFPP lacks market power in the Watson Station destination market and set a hearing to determine whether SFPP possessed market power in the origin market. In December 2000, an administrative law judge found that SFPP possessed market power over the Sepulveda origin market. On February 28, 2003, the FERC issued an order upholding that decision. SFPP filed a request for rehearing of that order on March 31, 2003. The FERC denied SFPP's request for rehearing on July 9, 2003. As part of its February 28, 2003 order denying SFPP's application for market-based ratemaking authority, the FERC remanded to the ongoing litigation in Docket No. OR96-2, et al. the question of whether SFPP's current rate for service on the Sepulveda pipeline is just and reasonable. A hearing in this proceeding was held in February and March 2005. SFPP asserted various defenses against the shippers' claims for reparations and refunds, including the existence of valid contracts with the shippers and grandfathering protection. In August 2005, the presiding administrative law judge issued an initial decision finding that for the period from 1993 to November 1997 (when the Sepulveda FERC tariff went into effect) the Sepulveda rate should have been lower. The administrative law judge recommended that SFPP pay reparations and refunds for alleged overcollections. SFPP filed in October 2005 a brief to the FERC taking exception to this and other portions of the initial decision. 15 OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond Shamrock Corporation filed a complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates, claiming they were unjust and unreasonable and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of SFPP's interstate rates, raising claims against SFPP's East and West Line rates similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed above, but expanding them to include challenges to SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2). Tosco Corporation filed a similar complaint in April 1998. The shippers seek both reparations and prospective rate reductions for movements on all of SFPP's lines. The FERC accepted the complaints and consolidated them into one proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC decision on review of the initial decision in Docket Nos. OR92-8, et al. In a companion order to Opinion No. 435, the FERC gave the complainants an opportunity to amend their complaints in light of Opinion No. 435, which the complainants did in January 2000. In August 2000, Navajo and Western filed complaints against SFPP's East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP's interstate pipeline rates. These complaints were consolidated with the ongoing proceeding in Docket No. OR96-2, et al. A hearing in this consolidated proceeding was held from October 2001 to March 2002. A FERC administrative law judge issued his initial decision in June 2003. The initial decision found that, for the years at issue, the complainants had shown substantially changed circumstances for rates on SFPP's West, North and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson Station and thus found that those rates should not be "grandfathered" under the Energy Policy Act of 1992. The initial decision also found that most of SFPP's rates at issue were unjust and unreasonable. On March 26, 2004, the FERC issued an order on the phase one initial decision. The FERC's phase one order reversed the initial decision by finding that SFPP's rates for its North and Oregon Lines should remain "grandfathered" and amended the initial decision by finding that SFPP's West Line rates (i) to Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no longer be "grandfathered" and are not just and reasonable. The FERC upheld these findings in its June 1, 2005 order, although it appears to have found substantially changed circumstances as to SFPP's West Line rates on a somewhat different basis than in the phase one order. The FERC's phase one order did not address prospective West Line rates and whether reparations are necessary. As discussed below, those issues have been addressed in the non-binding phase two initial decision issued by the presiding administrative law judge. The FERC's phase one order also did not address the "grandfathered" status of the Watson Station fee, noting that it would address that issue once it was ruled on by the Court of Appeals in its review of the FERC's Opinion No. 435 orders; as noted above, the FERC held in its June 1, 2005 order that the Watson Station fee is not grandfathered. Several of the participants in the proceeding requested rehearing of the FERC's phase one order. The FERC denied those requests in its June 1, 2005 order. In addition, several participants, including SFPP, filed petitions with the United States Court of Appeals for the District of Columbia Circuit for review of the FERC's phase one order. On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for review of the phase one order, which Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004, the Court referred the FERC's motion to the merits panel and directed the parties to address the issues in that motion on brief, thus effectively dismissing the FERC's motion. In the same order, the Court granted a motion to hold the petitions for review of the FERC's phase one order in abeyance and directed the parties to file motions to govern future proceeding 30 days after FERC disposition of the pending rehearing requests, which motions were filed in June and July of 2005; at least two such motions requested that the Court simultaneously review appeals of the March 26, 2004 phase one order and the June 1, 2005 order. Court action is now pending. The FERC's phase one order also held that SFPP failed to seek authorization for the accounting entries necessary to reflect in SFPP's books, and thus in its annual report to FERC ("FERC Form 6"), the purchase price adjustment ("PPA") arising from SFPP's 1998 acquisition by us. The phase one order directed SFPP to file for permission to reflect the PPA in its FERC Form 6 for the calendar year 1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP noted that it had previously requested such permission and that the FERC's 16 regulations require an oil pipeline to include a PPA in its Form 6 without first seeking FERC permission to do so. Several parties protested SFPP's compliance filing. In its June 1, 2005 order, the FERC accepted SFPP's compliance filing. In the June 1, 2005 order, the FERC directed SFPP to file a brief addressing whether the records developed in the OR92-8 and OR96-2 cases were sufficient to determine SFPP's entitlement to include an income tax allowance in its rates under the FERC's new policy statement. On June 16, 2005, SFPP filed its brief reviewing the pertinent records in the pending cases and applicable law and demonstrating its entitlement to a full income tax allowance in its interstate rates. SFPP's opponents in the two cases filed reply briefs contesting SFPP's presentation. It is not possible to predict with certainty the ultimate resolution of this issue, particularly given the likelihood that the FERC's policy statement and its decision in these cases will be appealed to the federal courts. On September 9, 2004, the presiding administrative law judge issued his non-binding initial decision in the phase two portion of this proceeding. If affirmed by the FERC, the phase two initial decision would establish the basis for prospective rates and the calculation of reparations for complaining shippers with respect to the West Line and East Line. However, as with the phase one initial decision, the phase two initial decision must be fully reviewed by the FERC, which may accept, reject or modify the decision. A FERC order on phase two of the case is expected during the fourth quarter of 2005. Any such order may be subject to further FERC review, review by the United States Court of Appeals for the District of Columbia Circuit, or both. We are not able to predict with certainty the final outcome of the pending FERC proceedings involving SFPP, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. The final outcome will depend, in part, on the outcomes of the appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP, complaining shippers, and an intervenor. We estimated, as of December 31, 2003, that shippers' claims for reparations totaled approximately $154 million and that prospective rate reductions would have an aggregate average annual impact of approximately $45 million. As the timing for implementation of rate reductions and the payment of reparations is extended, total estimated reparations and the interest accruing on the reparations increase. For each calendar quarter that implementation of the rate reductions sought is deferred, we estimate that reparations and accrued interest accumulates by approximately $9 million. We now assume that any potential rate reductions will be implemented no earlier than the fourth quarter of 2005 and that reparations and accrued interest thereon will be paid no earlier than the fourth quarter of 2006; however, the timing, and nature, of any rate reductions and reparations that may be ordered will likely be affected by the final disposition of the FERC's June 1, 2005 order, the FERC's income tax allowance inquiry in Docket No. PL05-5 and the application of the FERC's new policy statement on income tax allowances to SFPP in the OR92-8 and OR96-2 proceedings (described above). If the phase two initial decision were to be largely adopted by the FERC, the estimated reparations and rate reductions would be larger than noted above; however, we continue to estimate the combined annual impact of the rate reductions and the capital costs associated with financing the payment of reparations sought by shippers and accrued interest thereon to be approximately 15 cents of distributable cash flow per unit. We believe, however, that the ultimate resolution of these complaints will be for amounts substantially less than the amounts sought. Chevron complaint OR02-4 and OR03-5 proceedings. On February 11, 2002, Chevron, an intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a request for rehearing, which the FERC dismissed on September 25, 2002. In October 2002, Chevron filed a request for rehearing of the FERC's September 25, 2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron filed a petition for review of this denial at the U.S. Court of Appeals for the District of Columbia Circuit. On June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) - substantially similar to its previous complaint - and moved to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. Chevron requested that this new complaint be treated as if it were an amendment to its complaint in Docket No. OR02-4, which was previously dismissed by the FERC. By this request, Chevron sought to, in effect, back-date its complaint, and claim for reparations, to February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing Chevron's requests. On October 28, 2003 , the FERC accepted Chevron's complaint, but held it in abeyance pending the outcome of the Docket No. OR96-2, et al. proceeding. The FERC denied Chevron's request for 17 consolidation and for back-dating. On November 21, 2003, Chevron filed a petition for review of the FERC's October 28, 2003 Order at the Court of Appeals for the District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for review in OR02-4 on the basis that Chevron lacks standing to bring its appeal and that the case is not ripe for review. Chevron answered on September 10, 2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003, granted Chevron's motion to hold the case in abeyance pending the outcome of the appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the Court of Appeals granted Chevron's motion to have its appeal of the FERC's decision in OR03-5 consolidated with Chevron's appeal of the FERC's decision in the OR02-4 proceeding. Following motions to dismiss by FERC and SFPP, on December 10, 2004, the Court dismissed Chevron's petition for review in Docket No. OR03-5 and set Chevron's appeal of the FERC's orders in OR02-4 for briefing. On January 4, 2005, the Court granted Chevron's request to hold such briefing in abeyance until after final disposition of the OR96-2 proceeding. Chevron continues to participate in the Docket No. OR96-2 et al. proceeding as an intervenor. Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines, Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental Airlines, Inc. (collectively, the "Airlines") filed a complaint against SFPP at the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and SFPP's charge for its gathering enhancement service at Watson Station are not just and reasonable. The Airlines seek rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company, L.P., and ChevronTexaco Products Company all filed timely motions to intervene in this proceeding. Valero Marketing and Supply Company filed a motion to intervene one day after the deadline. SFPP answered the Airlines' complaint on October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's answer and on November 12, 2004, SFPP replied to the Airlines' response. In March and June 2005, the Airlines filed motions seeking expedited action on their complaint, and in July 2005, the Airlines filed a motion seeking to sever issues related to the Watson Station gathering enhancement fee from the OR04-3 proceeding and consolidate them in the proceeding regarding the justness and reasonableness of that fee that the FERC docketed as part of the June 1, 2005 order. In August 2005, FERC granted the Airlines' motion to sever and consolidate the Watson Station fee issues. OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC, which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that "substantially changed circumstances" have occurred, removing such protection. The complainants seek rate reductions and reparations for two years prior to the filing of their complaint and ask that the complaint be consolidated with the Airlines' complaint in the OR04-3 proceeding. ConocoPhillips Company, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 24, 2005. On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the FERC, which the FERC docketed as OR05-5. The complaint alleges that SFPP's interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that "substantially changed circumstances" have occurred, removing such protection. ConocoPhillips seeks rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 28, 2005. On February 25, 2005, the FERC consolidated the complaints in Docket Nos. OR05-4 and OR05-5 and held them in abeyance until after the conclusion of the various pending SFPP proceedings, deferring any ruling on the validity of the complaints. On March 28, 2005, BP West Coast and ExxonMobil requested rehearing of one aspect of the February 25, 2005 order; they argued that any tax allowance matters in these proceedings could not be decided in, or as a result of, the FERC's inquiry into income tax allowance in Docket No. PL05-5. On June 8, 2005, the FERC denied the request for rehearing. On March 14, 2005 and June 13, 2005, Valero and Chevron, respectively, filed untimely motions to intervene in the consolidated proceedings. FERC action on those motions is pending. The complaints continue to be held in abeyance. 18 North Line rate case, IS05-230 proceeding. In April 2005, SFPP filed to increase its North Line interstate rates to reflect increased costs, principally due to the installation of replacement pipe between Concord and Sacramento, California. Under FERC regulations, SFPP was required to demonstrate that there was a substantial divergence between the revenues generated by its existing North Line rates and its increased costs. SFPP's rate increase was protested by various shippers and accepted subject to refund by the FERC. An investigation and hearing regarding the rate increase is proceeding, with a hearing scheduled to commence in January 2006. Trailblazer Pipeline Company On March 22, 2005, Marathon Oil Company filed a formal complaint with FERC alleging that Trailblazer Pipeline Company violated the FERC's Negotiated Rate Policy Statement and the Natural Gas Act by failing to offer a recourse rate option for its Expansion 2002 capacity and by charging negotiated rates higher than the applicable recourse rates. Marathon is requesting that the FERC require Trailblazer to refund all amounts paid by Marathon above Trailblazer's Expansion 2002 recourse rate since the facilities went into service in May 2002, with interest. In addition, Marathon is asking the FERC to require Trailblazer to bill Marathon the Expansion 2002 recourse rate for future billings. Marathon estimates the amount of Trailblazer's refund to date is over $15 million. Trailblazer filed its response to Marathon's complaint on April 13, 2005. On May 20, 2005, the FERC issued an order denying the Marathon complaint and found that (i) Trailblazer did not violate FERC policy and regulations and (ii) there is insufficient justification to initiate further action under Section 5 of the Natural Gas Act to invalidate and change the negotiated rate. On June 17, 2005, Marathon filed its Request for Rehearing. On July 18, 2005, the FERC issued a procedural order titled "Order Granting Rehearing for Further Consideration," which allows additional time to act on the rehearing request. California Public Utilities Commission Proceeding ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission on April 7, 1997. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments. On October 1, 1997, the complainants filed testimony seeking prospective rate reductions aggregating approximately $15 million per year. On August 6, 1998, the CPUC issued its decision dismissing the complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of addressing the proper ratemaking treatment for partnership tax expenses, the calculation of environmental costs and the public utility status of SFPP's Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, complainants sought prospective rate reductions aggregating approximately $10 million per year. On March 16, 2000, SFPP filed an application with the CPUC seeking authority to justify its rates for intrastate transportation of refined petroleum products on competitive, market-based conditions rather than on traditional, cost-of-service analysis. On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC asserting that SFPP's California intrastate rates are not just and reasonable based on a 1998 test year and requesting the CPUC to reduce SFPP's rates prospectively. The amount of the reduction in SFPP rates sought by the complainants is not discernible from the complaint. The rehearing complaint was heard by the CPUC in October 2000 and the April 2000 complaint and SFPP's market-based application were heard by the CPUC in February 2001. All three matters stand submitted as of April 13, 2001, and resolution of these submitted matters may occur within the fourth quarter of 2005. The CPUC subsequently issued a resolution approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution approving the requested rate increase also required SFPP to submit cost data for 2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's overall rates for California intrastate transportation services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC's analysis of cost data to be 19 submitted by SFPP demonstrates that SFPP's California jurisdictional rates are unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data required by the CPUC, which submittal was protested by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and Chevron Products Company. Issues raised by the protest, including the reasonableness of SFPP's existing intrastate transportation rates, were the subject of evidentiary hearings conducted in December 2003 and may be resolved by the CPUC in the fourth quarter of 2005. On November 22, 2004, SFPP filed an application with the CPUC requesting a $9 million increase in existing intrastate rates to reflect the in-service date of SFPP's replacement and expansion of its Concord-to-Sacramento pipeline. The requested rate increase, which automatically became effective as of December 22, 2004 pursuant to California Public Utilities Code Section 455.3, is being collected subject to refund, pending resolution of protests to the application by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is not expected to resolve the matter before the first quarter of 2006. We currently believe the CPUC complaints seek approximately $15 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $31 million. There is no way to quantify the potential extent to which the CPUC could determine that SFPP's existing California rates are unreasonable. With regard to the amount of dollars potentially subject to refund as a consequence of the CPUC resolution requiring the provision by SFPP of cost-of-service data, referred to above, such refunds could total about $6 million per year from October 2002 to the anticipated date of a CPUC decision. SFPP believes the submission of the required, representative cost data required by the CPUC indicates that SFPP's existing rates for California intrastate services remain reasonable and that no refunds are justified. We believe that the resolution of such matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. Other Regulatory Matters In addition to the matters described above, we may face additional challenges to our rates in the future. Shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. In addition, since many of our assets are subject to regulation, we are subject to potential future changes in applicable rules and regulations that may have an adverse effect on our business, financial position, results of operations or cash flows. Carbon Dioxide Litigation Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed March 29, 2001). These cases were originally filed as class actions on behalf of classes of overriding royalty interest owners (Shores) and royalty interest owners (Bank of Denton) for damages relating to alleged underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes were initially certified at the trial court level, appeals resulted in the decertification and/or abandonment of the class claims. On February 22, 2005, the trial judge dismissed both cases for lack of jurisdiction. Some of the individual plaintiffs in these cases re-filed their claims in new lawsuits (discussed below). On May 13, 2004, William Armor, one of the former plaintiffs in the Shores matter whose claims were dismissed by the Court of Appeals for improper venue, filed a new case alleging the same claims for underpayment of royalties against the same defendants previously sued in the Shores case, including Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas filed May 13, 2004). Defendants filed their answers and special exceptions on June 4, 2004. Trial, originally scheduled for July 25, 2005, has been rescheduled for June 12, 2006. 20 On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state district court alleging the same claims for underpayment of royalties. Reddy and Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial District Court, Dallas County, Texas filed May 20, 2005). The defendants include Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. On June 23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the court in the Armor lawsuit granted the motion to transfer and consolidate and ordered that the Reddy lawsuit be transferred and consolidated into the Armor lawsuit. The defendants filed their answer and special exceptions on August 10, 2005. The consolidated Armor/Reddy trial is set for June 12, 2006. Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2 Company, L.P., is among the named counter-claim defendants in Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial District Court, Harris County, Texas filed June 17, 1998) (the "Bailey State Court Action"). The counter-claim plaintiffs are overriding royalty interest owners in the McElmo Dome Unit and have sued seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. In the Bailey State Court Action, the counter-claim plaintiffs asserted claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, negligence, negligence per se, unjust enrichment, violation of the Texas Securities Act, and open account. The trial court in the Bailey State Court Action granted a series of summary judgment motions filed by the counter-claim defendants on all of the counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004, one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege purported claims as a private relator under the False Claims Act and antitrust claims. The federal government elected to not intervene in the False Claims Act counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March 24, 2005) (the "Bailey Houston Federal Court Action"). Also on March 24, 2005, Bailey filed an instrument under seal in the Bailey Houston Federal Court Action that was later determined to be a motion to transfer venue of that case to the federal district court of Colorado, in which Bailey and two other plaintiffs have filed another suit against Kinder Morgan CO2 Company, L.P. asserting claims under the False Claims Act. The Houston federal district judge ordered that Bailey take steps to have the False Claims Act case pending in Colorado transferred to the Bailey Houston Federal Court Action, and also suggested that the claims of other plaintiffs in other carbon dioxide litigation pending in Texas should be transferred to the Bailey Houston Federal Court Action. In response to the court's suggestion, the case of Gary Shores et al. v. ExxonMobil Corp. et al., No. 05-1825 (S.D. Tex., Houston Division) was consolidated with the Bailey Houston Federal Court Action on July 18, 2005. That case, in which the plaintiffs assert claims for McElmo Dome royalty underpayment, includes Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., and Cortez Pipeline Company as defendants. Bailey has requested the Houston federal district court to transfer the Bailey Houston Federal Court Action to the federal district court of Colorado. Bailey also filed a petition for writ of mandamus in the Fifth Circuit Court of Appeals, asking that the Houston federal district court be required to transfer the case to the federal district court of Colorado. On June 3, 2005, the Fifth Circuit Court of Appeals denied Bailey's petition for writ of mandamus. On June 22, 2005, the Fifth Circuit denied Bailey's petition for rehearing en banc. Bailey has filed a petition for writ of certiorari in the United States Supreme Court. By order of the Houston federal district court, the counter-claim plaintiffs filed their respective counter-claims in the Bailey Houston Federal Court Action on June 29, 2005. The counter-claim plaintiffs asserted claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of contract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account. Bailey also asserted claims as a private relator under the False Claims Act and for violation of federal and Colorado antitrust laws. The counter-claim plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. Kinder Morgan CO2 Company, L.P. and the Shell plaintiffs have filed a motion for partial summary judgment and intend to seek dismissal of all of the counter-claim plaintiffs' claims through appropriate motions. No current trial date is set. On March 1, 2004, Bridwell Oil Company, one of the named defendants/counter-claim plaintiffs in the Bailey actions, filed a new matter in which it asserts claims which are virtually identical to the counter-claims it asserts against Shell CO2 Company, Ltd. in the Bailey lawsuit. Bridwell Oil Co. v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District Court, Wichita County, Texas filed March 1, 2004). The defendants in this action include Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, 21 defendants filed answers, special exceptions, pleas in abatement, and motions to transfer venue back to the Harris County District Court. On January 31, 2005, the Wichita County judge abated the case pending resolution of the Bailey State Court Action. The case remains abated. Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case involves claims by overriding royalty interest owners in the McElmo Dome and Doe Canyon Units seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome and Doe Canyon. The plaintiffs also possess a small working interest at Doe Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties owed by the defendants and also allege other theories of liability including breach of covenants, civil theft, conversion, fraud/fraudulent concealment, violation of the Colorado Organized Crime Control Act, deceptive trade practices, and violation of the Colorado Antitrust Act. In addition to actual or compensatory damages, plaintiffs seek treble damages, punitive damages, and declaratory relief relating to the Cortez Pipeline tariff and the method of calculating and paying royalties on McElmo Dome carbon dioxide. The Court denied plaintiffs' motion for summary judgment concerning alleged underpayment of McElmo Dome overriding royalties on March 2, 2005. The parties are continuing to engage in discovery. No trial date is currently set. J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New Mexico) involves a purported class action against Kinder Morgan CO2 Company, L.P. alleging that it has failed to pay the full royalty and overriding royalty ("royalty interests") on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit in the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit. The plaintiffs allege that they were members of a class previously certified as a class action by the United States District Court for the District of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege that Kinder Morgan CO2 Company's method of paying royalty interests is contrary to the settlement of the Feerer Class Action. Kinder Morgan CO2 Company has filed a Motion to Compel Arbitration of this matter pursuant to the arbitration provisions contained in the Feerer Class Action Settlement Agreement, which motion was denied by the trial court. An appeal of that ruling has been filed and is pending before the New Mexico Court of Appeals. No date for arbitration or trial is currently set. In addition to the matters listed above, various audits and administrative inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments on carbon dioxide produced from the McElmo Dome Unit are currently ongoing. These audits and inquiries involve various federal agencies, the State of Colorado, the Colorado oil and gas commission, and Colorado county taxing authorities. Commercial Litigation Matters Union Pacific Railroad Company Easements SFPP, L.P. and Union Pacific Railroad Company are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). SFPP was served with this lawsuit on August 17, 2004. SFPP expects that the trial in this matter will occur in late 2006. 22 ARB, Inc. Dispute ARB, Inc, a general contractor engaged by SFPP, L.P. to build a 20-inch diameter, 70-mile pipeline from Concord to Sacramento, California, and numerous third party contractors recorded liens against SFPP, L.P. based on an assertion that SFPP, L.P. owed ARB, Inc. and third party contractors additional payments ranging from $13.1 million to $16.8 million on the project. SFPP, L.P. engaged construction claims specialists and auditors to review project records and determine what additional payments, if any, should be made. On or about September 15, 2005, SFPP, L.P. agreed to settle all disputes with ARB, Inc. and third party contractors for substantially less than the recorded lien amounts. As part of the settlement, all recorded liens and other potential claims arising from the construction project were released with prejudice. RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial District). On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the First Supplemental Petition filed by RSM Production Corporation on behalf of the County of Zapata, State of Texas and Zapata County Independent School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition alleges that these taxing units relied on the reported volume and analyzed heating content of natural gas produced from the wells located within the appropriate taxing jurisdiction in order to properly assess the value of mineral interests in place. The suit further alleges that the defendants undermeasured the volume and heating content of that natural gas produced from privately owned wells in Zapata County, Texas. The Petition further alleges that the County and School District were deprived of ad valorem tax revenues as a result of the alleged undermeasurement of the natural gas by the defendants. On December 15, 2001, the defendants filed motions to transfer venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery requests on certain defendants. On July 11, 2003, defendants moved to stay any responses to such discovery. United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado). This action was filed on June 9, 1997 pursuant to the federal False Claims Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases, referred to as valuation claims. Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The United States' motion to dismiss most of plaintiff's valuation claims has been granted by the court. Grynberg has appealed that dismissal to the 10th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Subsequently, Grynberg's appeal was dismissed for lack of appellate jurisdiction. Discovery to determine issues related to the Court's subject matter jurisdiction arising out of the False Claims Act is complete. Briefing has been completed and oral arguments on jurisdiction were held before the Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to carbon dioxide production. Defendants have filed briefs opposing leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's Motion to Amend. On May 13, 2005, the Special Master issued his Report and Recommendations to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 23 1293. The Special Master found that there was a prior public disclosure of the mismeasurement fraud Grynberg alleged, and that Grynberg was not an original source of the allegations. As a result, the Special Master recommended dismissal on jurisdictional grounds of the Kinder Morgan defendants. On June 27, 2005, Grynberg filed a motion to modify and partially reverse the Special Master's recommendations and the Defendants filed a motion to adopt the Special Master's recommendations with modifications. We expect that the Federal Court in Wyoming may adopt the recommendations in this report and enter the formal dismissal order in the fourth quarter of this year. The District Court has scheduled an oral argument for December 9, 2005 on the motions concerning the Special Master's recommendations. It is likely that Grynberg will appeal any dismissal to the 10th Circuit Court of Appeals. Weldon Johnson and Guy Sparks, individually and as Representative of Others Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit Court, Miller County Arkansas). On October 8, 2004, plaintiffs filed the above-captioned matter against numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC; and Midcon Corp. (the "Kinder Morgan Defendants"). The Complaint purports to bring a class action on behalf of those who purchased natural gas from the Centerpoint defendants from October 1, 1994 to the date of class certification. The Complaint alleges that Centerpoint Energy, Inc., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-Centerpoint defendants, including the above-listed Kinder Morgan entities. The Complaint further alleges that in exchange for Centerpoint's purchase of such natural gas at above market prices, the non-Centerpoint defendants, including the above-listed Kinder Morgan entities, sell natural gas to Centerpoint's non-regulated affiliates at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The Complaint purports to assert claims for fraud, unlawful enrichment and civil conspiracy against all of the defendants, and seeks relief in the form of actual, exemplary and punitive damages, interest, and attorneys' fees. The Complaint was served on the Kinder Morgan Defendants on October 21, 2004. On November 18, 2004, the Centerpoint Defendants removed the case to the United States District Court, Western District of Arkansas, Texarkana Division, Civ. Action No. 04-4154. On January 26, 2005, the Plaintiffs moved to remand the case back to state court, which motion was granted on June 2, 2005. On July 11, 2005, the Kinder Morgan Defendants filed a Motion to Dismiss the Complaint, which motion is currently pending. On October 3, 2005, the Court issued a Scheduling and Case Management Order in which it ordered that discovery could proceed, scheduled a hearing on certain of the Kinder Morgan Defendants' Motions to Dismiss for February 14, 2006, deferred certain other motions to August 15, 2006, and scheduled a class certification hearing, if necessary, for March 16, 2006. Based on the information available to date and our preliminary investigation, the Kinder Morgan Defendants believe that the claims against them are without merit and intend to defend against them vigorously. Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th Judicial District Court, Harris County, Texas) On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original Petition and Application for Declaratory Relief against Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P., Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron Helium Company. Plaintiff added Enron Corp. as party in interest for Enron Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a Defendant. The claims against Enron Corp. were severed into a separate cause of action. Plaintiff's claims are based on a Gas Processing Agreement entered into on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company relating to gas produced in the Hugoton Field in Kansas and processed at the Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff also asserts claims relating to the Helium Extraction Agreement entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated March 14, 1988. Plaintiff alleges that Defendants failed to deliver propane and to allocate plant products to Plaintiff as required by the Gas Processing Agreement and originally sought damages of approximately $5.9 million. 24 Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third Amended Petition, Plaintiff alleges claims for breach of the Gas Processing Agreement and the Helium Extraction Agreement, requests a declaratory judgment and asserts claims for fraud by silence/bad faith, fraudulent inducement of the 1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach of a duty of good faith and fair dealing, negligent misrepresentation and conversion. As of April 7, 2003, Plaintiff alleged economic damages for the period from November 1987 through March 1997 in the amount of $30.7 million. On May 2, 2003, Plaintiff added claims for the period from April 1997 through February 2003 in the amount of $12.9 million. On June 23, 2003, Plaintiff filed a Fourth Amended Petition that reduced its total claim for economic damages to $30.0 million. On October 5, 2003, Plaintiff filed a Fifth Amended Petition that purported to add a cause of action for embezzlement. On February 10, 2004, Plaintiff filed its Eleventh Supplemental Responses to Requests for Disclosure that restated its alleged economic damages for the period of November 1987 through December 2003 as approximately $37.4 million. The matter went to trial on June 21, 2004. On June 30, 2004, the jury returned a unanimous verdict in favor of all defendants as to all counts. Final Judgment was entered in favor of the defendants on August 19, 2004. Plaintiff has appealed the jury's verdict to the 14th Court of Appeals for the State of Texas. Briefing on the appeal was completed in September 2005, and the appeal has been set for argument in November 2005. Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No. 2005-36174 (333rd Judicial District, Harris County, Texas). On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder Morgan Texas Pipeline, L.P. and alleged breach of contract for the purchase of natural gas storage capacity and for failure to pay under a profit-sharing arrangement. KMTP counterclaimed that Cannon Interests failed to provide it with five billion cubic feet of winter storage capacity in breach of the contract. The plaintiff is claiming approximately $13 million in damages. The parties are in the discovery phase. A trial date has been set for September 18, 2006. KMTP will defend the case vigorously, and based upon the information available to date, it believes that the claims against it are without merit and will be more than offset by its claims against Cannon-Interests. General Although no assurances can be given, we believe that we have meritorious defenses to all of these actions. Furthermore, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability. We also believe that these matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. Leukemia Cluster Litigation We are a party to several lawsuits in Nevada that allege that the plaintiffs have developed leukemia as a result of exposure to harmful substances. Based on the information available to date, our own preliminary investigation, and the positive results of investigations conducted by State and Federal agencies, we believe that the claims against us in these matters are without merit and intend to defend against them vigorously. The following is a summary of these cases. Marie Snyder, et al v. City of Fallon, United States Department of the Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No. cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court, State of Nevada, County of Washoe) ("Galaz II"); Frankie Sue Galaz, et al v. The United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District Court, District of Nevada)("Galaz III") 25 On July 9, 2002, we were served with a purported Complaint for Class Action in the Snyder case, in which the plaintiffs, on behalf of themselves and others similarly situated, assert that a leukemia cluster has developed in the City of Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to unspecified "environmental carcinogens" at unspecified times in an unspecified manner and are therefore "suffering a significantly increased fear of serious disease." The plaintiffs seek a certification of a class of all persons in Nevada who have lived for at least three months of their first ten years of life in the City of Fallon between the years 1992 and the present who have not been diagnosed with leukemia. The Complaint purports to assert causes of action for nuisance and "knowing concealment, suppression, or omission of material facts" against all defendants, and seeks relief in the form of "a court-supervised trust fund, paid for by defendants, jointly and severally, to finance a medical monitoring program to deliver services to members of the purported class that include, but are not limited to, testing, preventative screening and surveillance for conditions resulting from, or which can potentially result from exposure to environmental carcinogens," incidental damages, and attorneys' fees and costs. The defendants responded to the Complaint by filing Motions to Dismiss on the grounds that it fails to state a claim upon which relief can be granted. On November 7, 2002, the United States District Court granted the Motion to Dismiss filed by the United States, and further dismissed all claims against the remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs filed a Motion for Reconsideration and Leave to Amend, which was denied by the Court on December 30, 2002. Plaintiffs filed a Notice of Appeal to the United States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit affirmed the dismissal of this case. On December 3, 2002, plaintiffs filed an additional Complaint for Class Action in the Galaz I matter asserting the same claims in the same court on behalf of the same purported class against virtually the same defendants, including us. On February 10, 2003, the defendants filed Motions to Dismiss the Galaz I Complaint on the grounds that it also fails to state a claim upon which relief can be granted. This motion to dismiss was granted as to all defendants on April 3, 2003. Plaintiffs have filed a Notice of Appeal to the United States Court of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed the appeal, upholding the District Court's dismissal of the case. On June 20, 2003, plaintiffs filed an additional Complaint for Class Action (the "Galaz II" matter) asserting the same claims in Nevada State trial court on behalf of the same purported class against virtually the same defendants, including us (and excluding the United States Department of the Navy). On September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the Galaz II Complaint along with a Motion for Sanctions. On April 13, 2004, plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the entire case in State Court. The court has accepted the stipulation and the case was dismissed on April 27, 2004. Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters (now dismissed) filed yet another Complaint for Class Action in the United States District Court for the District of Nevada (the "Galaz III" matter) asserting the same claims in United States District Court for the District of Nevada on behalf of the same purported class against virtually the same defendants, including us. The Kinder Morgan defendants filed a Motion to Dismiss the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs filed a Motion for Withdrawal of Class Action, which voluntarily drops the class action allegations from the matter and seeks to have the case proceed on behalf of the Galaz family only. On December 5, 2003, the District Court granted the Kinder Morgan defendants' Motion to Dismiss, but granted plaintiff leave to file a second Amended Complaint. Plaintiff filed a Second Amended Complaint on December 13, 2003, and a Third Amended Complaint on January 5, 2004. The Kinder Morgan defendants filed a Motion to Dismiss the Third Amended Complaint on January 13, 2004. The Motion to Dismiss was granted with prejudice on April 30, 2004. On May 7, 2004, Plaintiff filed a Notice of Appeal in the United States Court of Appeals for the 9th Circuit. Briefing of the appeal has been completed and the parties are awaiting a decision. Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) ("Jernee"). On May 30, 2003, a separate group of plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against us 26 and several Kinder Morgan related entities and individuals and additional unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing "harmful substances and emissions and gases" to damage "the environment and health of human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins." Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified special, general and punitive damages. The Jernee case has been consolidated for pretrial purposes with the Sands case (see below). The Court has ordered the Plaintiffs to file Amended Complaints in both matters by November 7, 2005, and the Defendants to file renewed Motions to Dismiss by December 5, 2005. Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second Judicial District Court, State of Nevada, County of Washoe) ("Sands"). On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against us and several Kinder Morgan related entities and individuals and additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing "harmful substances and emissions and gases" to damage "the environment and health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins. Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified special, general and punitive damages. The Kinder Morgan defendants were served with the Complaint on January 10, 2004. The Sands case has been consolidated for pretrial purposes with the Jernee case (see above). The Court has ordered the Plaintiffs to file Amended Complaints in both matters by November 7, 2005, and the Defendants to file renewed Motions to Dismiss by December 5, 2005. Pipeline Integrity and Ruptures Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona. On January 28, 2005, Meritage Homes Corp. and its above-named affiliates filed a Complaint in the above-entitled action against us and SFPP, LP. The Plaintiffs are homebuilders who constructed a subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30, 2003 pipeline rupture and accompanying release of petroleum products, soil and groundwater adjacent to, on and underlying portions of Silver Creek II became contaminated. Plaintiffs allege that they have incurred and continue to incur costs, damages and expenses associated with the delay of closings of home sales within Silver Creek II and damage to their reputation and goodwill as a result of the rupture and release. Plaintiffs' complaint purports to assert claims for negligence, breach of contract, trespass, nuisance, strict liability, subrogation and indemnity, and negligence per se. Plaintiffs seek "no less than $1,500,000 in compensatory damages and necessary response costs," a declaratory judgment, interest, punitive damages and attorneys' fees and costs. The parties have agreed to submit the claims to arbitration and are currently engaged in discovery. We dispute the legal and factual bases for many of Plaintiffs' claimed compensatory damages, deny that punitive damages are appropriate under the facts, and intend to vigorously defend this action. Walnut Creek, California Pipeline Rupture On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a water main replacement project hired by East Bay Municipal Utility District, struck and ruptured an underground petroleum pipeline owned and operated by SFPP, LP in Walnut Creek, California. An explosion occurred immediately following the rupture that resulted in five fatalities and several injuries to employees or contractors of Mountain Cascade. On May 5, 2005, the California Division of Occupational Safety and Health ("CalOSHA") issued two civil citations against us relating to this incident assessing civil fines of $140,000 based upon our alleged failure to mark the 27 location of the pipeline properly prior to the excavation of the site by the contractor. CalOSHA is continuing to investigate the facts and circumstances surrounding the incident for possible criminal violations. In addition, on June 27, 2005, the Office of the California State Fire Marshal, Pipeline Safety Division ("CSFM") issued a Notice of Violation against us which also alleges that we did not properly mark the location of the pipeline in violation of state and federal regulations. The CSFM assessed a proposed civil penalty of $500,000. The location of the incident was not our work site, nor did we have any direct involvement in the water main replacement project. We believe that SFPP acted in accordance with applicable law and regulations, and further that according to California law, excavators, such as the contractor on the project, must take the necessary steps (including excavating with hand tools) to confirm the exact location of a pipeline before using any power operated or power driven excavation equipment. Accordingly, we disagree with certain of the findings of CalOSHA and the CSFM, and we plan to appeal the civil penalties while, at the same time, continuing to work cooperatively with CalOSHA and the CSFM to resolve these matters. As a result of this accident, the following wrongful death, personal injury and/or property damage claims have been filed against us, which cases have been consolidated for pretrial purposes in the Superior Court of California, Contra Costa County. Juana Lilian Arias, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P., Mountain Cascade, Inc., and Does 1-30, No. RG05195567 (Superior Court, Alameda County, California). This complaint for personal injuries and wrongful death was filed on January 26, 2005. Plaintiffs allege that Victor Javier Rodriguez was killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that defendants failed to properly locate and mark the location of the petroleum pipeline. The complaint purports to assert claims for negligence, unfair competition, strict liability and intentional misrepresentation. Plaintiffs seek unspecified general damages, incidental damages, economic damages, disgorgement of profits, exemplary damages, interest, attorneys' fees and costs. Marilu Angeles, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P., Mountain Cascade, Inc., Does 1-30 and Mariel Hernandez, No. RG05195680 (Superior Court, Alameda County, California). This complaint for personal injuries and wrongful death was filed on January 26, 2005. Plaintiffs allege that Israel Hernandez was killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that defendants failed to properly locate and mark the location of the petroleum pipeline. The complaint purports to assert claims for negligence, unfair competition, strict liability and intentional misrepresentation. Plaintiffs seek unspecified general damages, incidental damages, economic damages, disgorgement of profits, exemplary damages, interest, attorneys' fees and costs. Jeremy and Johanna Knox v. Mountain Cascade, Inc, Kinder Morgan Energy Partners of Houston, Inc., and Does 1 to 50, No. C 05-00281 (Superior Court, Contra Costa County, California). This complaint for personal injuries was filed on February 2, 2005. Plaintiffs allege that Jeremy Knox was injured as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that defendants failed to properly locate and mark the location of the petroleum pipeline. Plaintiffs assert claims for negligence, loss of consortium, and exemplary damages in an unspecified amount. Laura Reyes et al. v. East Bay Municipal Utility District, Mountain Cascade, Inc. and Kinder Morgan Energy Partners, L.P , Kinder Morgan G.P., Inc.; SFPP, L.P.; Camp Dresser & McKee Inc.; Carollo Engineers; Comforce Technical Services, Inc. et al.; No. RG05207720 (Superior Court, Alameda County, California). This complaint was originally filed on or about April 14, 2005, and a Second Amended Complaint was filed on June 23, 2005. The suit is brought on behalf of Laura Reyes, wife of deceased welder Miguel Reyes, and their three minor children. The complaint, as amended, includes claims of wrongful death and negligence, strict liability, unfair business practices, and intentional misrepresentation, and seeks unspecified compensatory and exemplary damages. Patrick and Victoria Farley v. Mountain Cascade, Inc., Kinder Morgan Energy Partners of Houston, Inc.; East Bay Municipal Utility District; Carollo Engineers, P.C.; Comforce Technical Services; and Does 1-100; No. 05-01573 (Superior Court, Contra Costa County, California). Plaintiffs allege that Patrick Farley was injured as a result of the rupture by Mountain Cascade, Inc. of SFPP, L.P.'s petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that defendants failed to properly locate and mark the location of the petroleum pipeline. Plaintiffs assert claims for negligence, loss of consortium, and exemplary damages in an unspecified amount. Maria Ramos, individually and as successor in interest to Javier Ramos, Erica Ramos, Ramona Ramos, Gicelda Ramos, Jasmin Ramos, and Gerardo Ramos, by and through their guardian ad litem Maria Ramos v. East Bay Municipal Utility District; Kinder Morgan, Inc.; Kinder Morgan Energy Partners, L.P.; Kinder Morgan G.P., Inc.; SFPP, L.P.; City of Walnut Creek; Contra Costa County and Does 1-100; No. C-05-01840 (Superior Court, Contra Costa County, California). This complaint for personal injuries and wrongful death was filed on September 21, 2005. Plaintiffs allege that Javier Ramos was killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, L.P.'s petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that the Kinder Morgan Defendants failed to properly locate and mark the location of the petroleum pipeline. The complaint purports to assert claims for negligence, unfair competition, strict liability and intentional misrepresentation. Plaintiffs seek unspecified general damages, incidental damages, economic damages, exemplary damages, interest, attorneys' fees and costs. Chong Im, Kevin C. Im and Jackie Im, individually and as successor in interest to Tae Im v. Kinder Morgan Inc.; Kinder Morgan Energy partners, L.P.; East Bay Municipal Utility District; SFPP, L.P.; Camp Dresser & McKee, Inc.; Carollo Engineers; Comforce Technical Services, Inc.; and Does 1-100: No. C-05-02077 (Superior Court, Contra Costa County, California). This complaint for personal injuries and wrongful death was filed on September 30, 2005. Plaintiffs allege that Tae Im was killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, L.P.'s petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that the Kinder Morgan Defendants failed to properly locate and mark the location of the petroleum pipeline. The complaint purports to assert claims for negligence, willful misconduct, and strict liability. Plaintiffs seek unspecified general damages, incidental damages, economic damages, exemplary damages, interest, attorneys' fees and costs. United States Automobile Association v. East Bay Municipal Utilities District; Mountain Cascade, Inc.; Kinder Morgan Energy Partners, L.P.; SFPP, L.P.; Kinder Morgan G.P., Inc; Kinder Morgan, Inc,; Matamoros Pipeline, Inc.; Carollo Engineers, P.C.; and Does 1-100; No. MSCO5-02128 (Superior Court, Contra Costa County, California). Plaintiff United States Automobile Association ("USAA") filed this subrogation action against the defendants in order to recover approximately $1.8 million plus interest and costs which USAA paid to its insured, Enos Chabot, for damages to its insured's house, allegedly caused as a result of the rupture by Mountain Cascade, Inc. of SFPP, L.P.'s petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiff asserts causes of action for negligence, strict liability, res ipsa, and negligence per se against the defendants. Based upon our initial investigation of the cause of the rupture of SFPP, LP's petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and fire, we intend to deny liability for the resulting deaths, injuries and damages, to vigorously defend against such claims, and to seek contribution and indemnity from the responsible parties. Cordelia, California On April 28, 2004, we discovered a spill of diesel fuel into a marsh near Cordelia, California from a section of our Pacific operations' 14-inch Concord 28 to Sacramento, California products pipeline. Estimates indicated that the size of the spill was approximately 2,450 barrels. Upon discovery of the spill and notification to regulatory agencies, a unified response was implemented with the United States Coast Guard, the California Department of Fish and Game, the Office of Spill Prevention and Response and us. The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on May 2, 2004. We have completed recovery of free flowing diesel from the marsh and have completed an enhanced biodegradation program for removal of the remaining constituents bound up in soils. The property has been turned back to the owners for its stated purpose. There will be ongoing monitoring under the oversight of the California Regional Water Quality Control Board until the site conditions demonstrate there are no further actions required. We are currently in negotiations with the United States Environmental Protection Agency, the United States Fish & Wildlife Service, the California Department of Fish & Game and the San Francisco Regional Water Quality Control Board regarding potential civil penalties and natural resource damages assessments. In April 2005, we were informed by the office of the Attorney General of California that the office was contemplating filing criminal charges against us claiming discharge of diesel fuel arising from the April 2004 rupture from a section of our Pacific operations' 14-inch Concord to Sacramento, California products pipeline and the failure to make timely notice of the discharge to appropriate state agencies. In addition, we were told that the California Attorney General was also contemplating filing charges alleging other releases and failures to provide timely notice regarding certain environmental incidents at certain of our facilities in California. On April 26, 2005, we announced that we had entered into an agreement with the Attorney General of the State of California and the District Attorney of Solano County, California, to settle misdemeanor charges of the unintentional, non-negligent discharge of diesel fuel resulting from this release and the failure to provide timely notice of a threatened discharge to appropriate state agencies as well as other potential claims in California regarding alleged notice and discharge incidents. In addition to the charges settled by this agreement, we entered into an agreement in principle to settle similar additional misdemeanor charges in Los Angeles County, California, in connection with the unintentional, non-negligent release of approximately five gallons of diesel fuel at our Carson refined petroleum products terminal in Los Angeles Harbor in May 2004. Under the settlement agreement related to the Cordelia, California incident, SFPP, L.P. agreed to plead guilty to four misdemeanors and to pay approximately $5.2 million in fines, penalties, restitution, environmental improvement project funding, and enforcement training in the State of California, and agreed to be placed on informal, unsupervised probation for a term of three years. Under the settlement agreement related to the Carson terminal incident, we agreed to plead guilty to two additional misdemeanors and to pay approximately $0.2 million in fines and penalties. In addition, we are currently in negotiations with the United States Environmental Protection Agency, the United States Fish & Wildlife Service, the California Department of Fish & Game and the San Francisco Regional Water Quality Control Board regarding potential civil penalties and natural resource damages assessments. In the first nine months of 2005, we have included a combined $8.4 million as general and administrative expense related to these environmental issues, and we have made payments in the amount of $0.4 million as of September 30, 2005. Since the April 2004 release in the Suisun Marsh area near Cordelia, California, we have cooperated fully with federal and state agencies and have worked diligently to remediate the affected areas. As of September 30, 2005, the remediation was substantially complete. Baker, California In November 2004, our CALNEV pipeline, which transports refined petroleum products from Colton, California to Las Vegas, Nevada, experienced a failure in the line from external damage, resulting in a release of gasoline that affected approximately two acres of land in the high desert administered by The Bureau of Land Management, an agency within the U.S. Department of the Interior. Remediation has been conducted and continues for product in the soils. All agency requirements have been met and the site will be closed upon completion of the soil remediation. 29 Oakland, California In February 2005, we were contacted by the U.S. Coast Guard regarding a potential release of jet fuel in the Oakland, California area. Our northern California team responded and discovered that one of our product pipelines had been damaged by a third party, which resulted in a release of jet fuel which migrated to the storm drain system. We have coordinated the remediation of the impacts from this release, and are investigating the identity of the third party who damaged the pipeline in order to obtain contribution, indemnity, and to recover any damages associated with the rupture. Donner Summit, California In April 2005, our SFPP pipeline in Northern California, which transports refined petroleum products to Reno, Nevada, experienced a failure in the line from external damage, resulting in a release of product that affected a limited area adjacent to the pipeline near the summit of Donner Pass. The release was located on land administered by the Forest Service, an agency within the U.S. Department of Agriculture. Initial remediation has been conducted in the immediate vicinity of the pipeline. All agency requirements have been met and the site will be closed upon completion of the remediation. Long Beach, California In May 2005, our SFPP, L.P. pipeline in Long Beach, California experienced a failure at the block valve and affected a limited area adjacent to the pipeline. The release was located along the Southern California Edison power line right-of-way and also affected a botanical nursery. Initial remediation has been conducted and no further remediation appears to be necessary. All agency requirements have been met and this site will be closed upon completion of the remediation. El Paso, Texas In May 2005, our SFPP, L.P. pipeline in El Paso, Texas experienced a failure on the 12-inch line located on the Fort Bliss Army Base. Initial remediation has been conducted and we are conducting an evaluation to determine the extent of impacts. All agency requirements have been met and this site will be closed upon completion of the remediation. Plant City, Florida In September 2005, our Central Florida Pipeline, which transports refined petroleum products from Tampa, Florida to Orlando, Florida, experienced a pipeline release of diesel fuel affecting approximately two acres of land. Several residential properties and commercial properties were impacted by the release. Initial remedial measures have been implemented involving removal of impacted soils, vegetation and restoration of the landowner's properties. All agency requirements have been met and we are in the process of implementing long-term site assessment and remediation activities. Proposed Office of Pipeline Safety Civil Penalty and Compliance Order On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order concerning alleged violations of certain federal regulations concerning our products pipeline integrity management program. The violations alleged in the Proposed Order are based upon the results of inspections of our integrity management program at our products pipelines facilities in Orange, California and Doraville, Georgia conducted in April and June of 2003, respectively. As a result of the alleged violations, the OPS seeks to have us implement a number of changes to our integrity management program and also seeks to impose a proposed civil penalty of approximately $0.3 million. We have already addressed a number of the concerns identified by the OPS and intend to continue to work with the OPS to ensure that our integrity management program satisfies all applicable regulations. However, we dispute some of the OPS findings and disagree that civil penalties are appropriate, and therefore have requested an administrative hearing on these matters according to the U.S. Department of Transportation regulations. An administrative hearing was held on April 11 and 12, 2005. We have provided supplemental information to the hearing officer and to the OPS. It 30 is anticipated that the decision in this matter and potential administrative order will be issued by the end of the first quarter of 2006. Pipeline and Hazardous Materials Safety Administration Corrective Action Order On August 26, 2005, we announced that we had received a Corrective Action Order issued by the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration ("PHMSA"). The Corrective Order instructs us to comprehensively address potential integrity threats along the pipelines that comprise our Pacific operations. The Corrective Order focused primarily on eight pipeline incidents, seven of which occurred in the State of California. PHMSA attributed five of the eight incidents to "outside force damage," such as third-party damage caused by an excavator or damage caused during pipeline construction. The Corrective Order requires us to perform a thorough analysis of recent pipeline incidents, provide for a third-party independent review of our operations and procedural practices, and restructure our internal inspections program. While we expect to appeal certain elements in the Corrective Order, we have been working, and will continue to work, cooperatively with PHMSA to resolve the matters identified in the Order. Furthermore, we have reviewed all of our policies and procedures and are currently implementing various measures to strengthen our integrity management program, including a comprehensive evaluation of internal inspection technologies and other methods to protect our pipelines. We do not expect that our compliance with the Corrective Order will have a material adverse effect on our business, financial position, results of operations or cash flows. Federal Investigation at Cora and Grand Rivers Coal Facilities On June 22, 2005, we announced that the Federal Bureau of Investigation is conducting an investigation related to our coal terminal facilities located in Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal terminals that occurred from 1997 through 2001. During this time period, we sold excess coal from these two terminals for our own account, generating less than $15 million in total net sales. Excess coal is the weight gain that results from moisture absorption into existing coal during transit or storage and from scale inaccuracies, which are typical in the industry. During the years 1997 through 1999, we collected, and, from 1997 through 2001, we subsequently sold, excess coal for our own account, as we believed we were entitled to do under then-existing customer contracts. As of June 30, 2005, we had conducted an internal investigation of the allegations and discovered no evidence of wrongdoing or improper activities at these two terminals. Furthermore, we are contacting customers of these terminals during the applicable time period and will offer to share information with them regarding our excess coal sales. Over the five year period from 1997 to 2001, we moved almost 75 million tons of coal through these terminals, of which less than 1.4 million tons were sold for our own account (including both excess coal and coal purchased on the open market). We have not added to our inventory of excess coal since 1999 and we have not sold coal for our own account since 2001, except for minor amounts of scrap coal. We are fully cooperating with federal law enforcement authorities in this investigation. In September 2005, we responded to a subpoena in this matter by producing a large volume of documents, which, we understand, is being reviewed by the FBI and auditors from the Tennessee Valley Authority, which is a customer of the Cora and Grand Rivers terminals. We do not expect that the resolution of the investigation will have a material adverse impact on our business, financial position, results of operations or cash flows. Environmental Matters We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. 31 We are currently involved in the following governmental proceedings related to compliance with environmental regulations associated with our assets and have established a reserve to address the costs associated with the cleanup: - several groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by the California Regional Water Quality Control Board and several other state agencies for assets associated with SFPP, L.P.; - groundwater and soil remediation efforts under administrative orders issued by various regulatory agencies on those assets purchased from GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, KM Liquids Terminals L.P., CALNEV Pipe Line LLC and Central Florida Pipeline LLC; - groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory agencies on those assets purchased from ExxonMobil; ConocoPhillips; and Charter Triad, comprising Kinder Morgan Southeast Terminals, LLC.; and - groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory agencies on those assets comprising Plantation Pipe Line Company. San Diego, California In June 2004, we entered into discussions with the City of San Diego with respect to impacted groundwater beneath the City's stadium property in San Diego resulting from operations at the Mission Valley terminal facility. The City has requested that SFPP work with the City as they seek to re-develop options for the stadium area including future use of both groundwater aquifer and real estate development. The City of San Diego and SFPP are working cooperatively towards a settlement and a long-term plan as SFPP continues to remediate the impacted groundwater. We do not expect the cost of any settlement and remediation plan to be material. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc. and ST Services, Inc. On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the Superior Court of New Jersey, Gloucester County. We filed our answer to the Complaint on June 27, 2003, in which we denied ExxonMobil's claims and allegations as well as included counterclaims against ExxonMobil. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and owned currently by ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil performed an environmental site assessment of the terminal required prior to sale pursuant to state law. During the site assessment, ExxonMobil discovered items that required remediation and the New Jersey Department of Environmental Protection issued an order that required ExxonMobil to perform various remediation activities to remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is still remediating the site and has not been removed as a responsible party from the state's cleanup order; however, ExxonMobil claims that the remediation continues because of GATX Terminals' storage of a fuel additive, MTBE, at the terminal during GATX Terminals' ownership of the terminal. When GATX Terminals sold the terminal to ST Services, the parties indemnified one another for certain environmental matters. When GATX Terminals was sold to us, GATX Terminals' indemnification obligations, if any, to ST Services may have passed to us. Consequently, at issue is any indemnification obligations we may owe to ST Services in respect to environmental remediation of MTBE at the terminal. The Complaint seeks any and all damages related to remediating MTBE at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit for remediating MTBE at the terminal. The parties have recently completed limited discovery. In October 2004, the judge assigned to the case dismissed himself from the case based on a conflict, and the new judge has ordered the parties to participate in mandatory mediation. The mediation is currently scheduled for November 2, 2005. 32 Other Environmental On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement Action related to our CO2 segment's Snyder Gas Plant. On August 4, 2005, we received an executed settlement agreement with the TCEQ for approximately $0.3 million, of which approximately $0.1 million was applied to a supplemental environmental project in Scurry County, Texas. Our review of assets related to Kinder Morgan Interstate Gas Transmission LLC indicates possible environmental impacts from petroleum and used oil releases into the soil and groundwater at nine sites. Additionally, our review of assets related to Kinder Morgan Texas Pipeline and Kinder Morgan Tejas indicates possible environmental impacts from petroleum releases into the soil and groundwater at nine sites. Further delineation and remediation of any environmental impacts from these matters will be conducted. Reserves have been established to address these issues. See "--Pipeline Integrity and Ruptures" above for information with respect to the environmental impact of recent ruptures of some of our pipelines. We are also involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. Although no assurance can be given, we believe that the ultimate resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur. Many factors may change in the future affecting our reserve estimates, such as regulatory changes, groundwater and land use near our sites, and changes in cleanup technology. As of September 30, 2005, we have accrued an environmental reserve of $26.7 million. Other We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows. 4. Asset Retirement Obligations We account for our legal obligations associated with the retirement of long-lived assets pursuant to Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. Under SFAS No. 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. In our CO2 business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of September 30, 2005, we have 33 recognized asset retirement obligations in the aggregate amounts of $35.9 million relating to these requirements at existing sites within our CO2 business segment. In our Natural Gas Pipelines business segment, if we were to cease providing utility services, we would be required to remove surface facilities from land belonging to our customers and others. Our Texas intrastate natural gas pipeline group has various condensate drip tanks and separators located throughout its natural gas pipeline systems, as well as inactive gas processing plants, laterals and gathering systems which are no longer integral to the overall mainline transmission systems, and asbestos-coated underground pipe which is being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission system has compressor stations which are no longer active and other miscellaneous facilities, all of which have been officially abandoned. We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities. As of September 30, 2005, we have recognized asset retirement obligations in the aggregate amounts of $1.7 million relating to the businesses within our Natural Gas Pipelines business segment. We have included $0.8 million of our total asset retirement obligations as of September 30, 2005 with "Accrued other current liabilities" in our accompanying consolidated balance sheet. The remaining $36.8 million obligation is reported separately as a non-current liability. No assets are legally restricted for purposes of settling our asset retirement obligations. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the nine months ended September 30, 2005 and 2004 is as follows (in thousands):
Nine Months Ended September 30, ------------------------------- 2005 2004 ------------ ------------ Balance at beginning of period........ $ 38,274 $ 35,708 Liabilities incurred................ 521 130 Liabilities settled................. (1,497) (516) Accretion expense................... 807 1,559 Revisions in estimated cash flows... (522) - ------------ ------------ Balance at end of period.............. $ 37,583 $ 36,881 ============ ============
5. Distributions On August 12, 2005, we paid a cash distribution of $0.78 per unit to our common unitholders and our Class B unitholders for the quarterly period ended June 30, 2005. KMR, our sole i-unitholder, received 909,009 additional i-units based on the $0.78 cash distribution per common unit. The distributions were declared on July 20, 2005, payable to unitholders of record as of July 29, 2005. On October 19, 2005, we declared a cash distribution of $0.79 per unit for the quarterly period ended September 30, 2005. The distribution will be paid on November 14, 2005, to unitholders of record as of October 31, 2005. Our common unitholders and Class B unitholders will receive cash. KMR will receive a distribution in the form of additional i-units based on the $0.79 distribution per common unit. The number of i-units distributed will be 932,292. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.016360) will be issued. The fraction was determined by dividing: - $0.79, the cash amount distributed per common unit by - $48.288, the average of KMR's limited liability shares' closing market prices from October 13-26, 2005, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange. 6. Intangibles Our intangible assets include goodwill, lease value, contracts and agreements. All of our intangible assets having definite lives are being 34 amortized on a straight-line basis over their estimated useful lives. Following is information related to our intangible assets still subject to amortization and our goodwill (in thousands):
September 30, December 31, 2005 2004 Goodwill Gross carrying amount.... $ 800,180 $ 746,980 Accumulated amortization. (14,142) (14,142) ----------- ----------- Net carrying amount...... 786,038 732,838 ----------- ----------- Lease value Gross carrying amount.... 6,592 6,592 Accumulated amortization. (1,134) (1,028) ----------- ----------- Net carrying amount...... 5,458 5,564 ----------- ----------- Contracts and other Gross carrying amount.... 210,480 10,775 Accumulated amortization. (5,373) (1,055) ----------- ----------- Net carrying amount...... 205,107 9,720 ----------- ----------- Total intangibles, net..... $ 996,603 $ 748,122 =========== ===========
Amortization expense on our intangibles consisted of the following (in thousands):
Three Months Ended September 30, Nine Months Ended September 30, 2005 2004 2005 2004 Lease value............ $ 35 $ 35 $ 106 $ 105 Contracts and other.... 3,487 205 4,318 535 ----------- ----------- ----------- ----------- Total amortization..... $ 3,522 $ 240 $ 4,424 $ 640 =========== =========== =========== ===========
As of September 30, 2005, our weighted average amortization period for our intangible assets was approximately 23.3 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $10.7 million, $10.4 million, $10.3 million, $10.1 million and $10.1 million, respectively. Goodwill Changes in the carrying amount of goodwill for the nine months ended September 30, 2005 are summarized as follows (in thousands):
Products Natural Gas Pipelines Pipelines CO2 Terminals Total Balance as of December 31, 2004.... $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838 Acquisitions and purchase price 13,088 12,092 - 28,020 53,200 adjs............................... Disposals........................ - - - - - Impairments...................... - - - - - ----------- ----------- ----------- ----------- ----------- Balance as of September 30, 2005... $ 276,270 $ 262,410 $ 46,101 $ 201,257 $ 786,038 =========== =========== =========== =========== ===========
Equity Method Goodwill In addition, pursuant to ABP No. 18, any premium paid by an investor, which is analogous to goodwill, must be identified. The premium, representing excess cost over underlying fair value of net assets accounted for under the equity method of accounting, is referred to as equity method goodwill, and is not subject to amortization but rather to impairment testing. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. This test requires equity method investors to continue to assess impairment of investments in investees by considering whether declines in the fair values of those investments, versus carrying values, may be other than temporary in nature. Therefore, in addition to our annual impairment test of goodwill, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives in accordance with APB Opinion No. 18. 35 7. Debt Our outstanding short-term debt as of September 30, 2005 was $546.7 million. The balance consisted of: - $538.7 million of commercial paper borrowings; - a $5 million portion of 7.84% senior notes (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); - a $4.2 million portion of 8.85% senior notes (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes); and - an offset of $1.2 million (which represents the net of other borrowings and the accretion of discounts on our senior note issuances). As of September 30, 2005, we intended and had the ability to refinance all of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. The weighted average interest rate on all of our borrowings was approximately 5.069% during the third quarter of 2005 and 4.591% during the third quarter of 2004. Credit Facility On August 5, 2005, we increased our existing bank facility from $1.25 billion to $1.6 billion, and we extended the maturity one year to August 18, 2010. Wachovia Bank, National Association continues as the administrative agent. The borrowing rates decreased slightly under the extended agreement, and there were minor changes to the financial covenants as compared to the covenants under our previous bank facility. There were no borrowings under our five-year credit facility as of September 30, 2005, and no borrowings under our previous facility as of December 31, 2004. The amount available for borrowing under our credit facility as of September 30, 2005 was reduced by: - our outstanding commercial paper borrowings ($538.7 million as of September 30, 2005); - a combined $609 million in four letters of credit that support our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids, oil and carbon dioxide; - a combined $50 million in two letters of credit that support tax-exempt bonds; and - $8.1 million of other letters of credit supporting other obligations of us and our subsidiaries. 36 Interest Rate Swaps Information on our interest rate swaps is contained in Note 10. Commercial Paper Program On August 5, 2005, we increased our commercial paper program by $350 million to provide for the issuance of up to $1.6 billion. Our new $1.6 billion unsecured 5-year credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. As of September 30, 2005, we had $538.7 million of commercial paper outstanding with an average interest rate of 3.7404%. Senior Notes On March 15, 2005, we paid $200 million to retire the principal amount of our 8.0% senior notes that matured on that date. We borrowed the necessary funds under our commercial paper program. On March 15, 2005, we closed a public offering of $500 million in principal amount of 5.80% senior notes due March 15, 2035 at a price to the public of 99.746% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $494.4 million. We used the proceeds to reduce the outstanding balance on our commercial paper borrowings. International Marine Terminals Debt Since February 1, 2002, we have owned a 66 2/3% interest in International Marine Terminals partnership. The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. On March 15, 2005, these bonds were refunded and the maturity date was extended from March 15, 2006 to March 15, 2025. No other changes were made under the bond provisions. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees. General Stevedores, L.P. Debt Effective July 31, 2005, we acquired all of the partnership interests in General Stevedores, L.P. (see Note 3). As part of our purchase price, we assumed approximately $3.0 million in principal amount of outstanding debt, primarily consisting of commercial bank loans. In August 2005, we paid the $3.0 million outstanding debt balance, and following our repayment, General Stevedores, L.P. had no outstanding debt. Kinder Morgan Texas Pipeline, L.P. Debt Effective August 1, 2005, we acquired a natural gas storage facility in Liberty County, Texas (see Note 3). As part of our purchase price, we assumed an aggregate principal amount of $49.2 million of privately placed unsecured senior notes. Our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes. The unsecured senior notes have a fixed annual interest rate of 8.85% and the assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million. The final payment is due January 2, 2014. Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid. The notes also contain certain covenants similar to those contained in our current five-year, unsecured revolving credit facility. We do not believe that these covenants will materially affect distributions to our partners. 37 Contingent Debt We apply the provisions of Financial Accounting Standards Board Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our agreements that contain guarantee or indemnification clauses. These disclosure provisions expand those required by SFAS No. 5, "Accounting for Contingencies," by requiring a guarantor to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance is remote. The following is a description of our contingent debt agreements. Cortez Pipeline Company Debt Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline Company - 13% partner) are required, on a several, percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company partners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company partners under the Throughput and Deficiency Agreement. Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company shares our several guaranty obligations jointly and severally; however, we are obligated to indemnify Shell for liabilities it incurs in connection with such guaranty. With respect to Cortez's long-term revolving credit facility, Shell is released of its guaranty obligations on December 31, 2006. Furthermore, with respect to Cortez's short-term commercial paper program and Series D notes, we must use commercially reasonable efforts to have Shell released of its guaranty obligations by December 31, 2006. If we are unable to obtain Shell's release in respect of the Series D Notes by that date, we are required to provide Shell with collateral (a letter of credit, for example) to secure our indemnification obligations to Shell. As of September 30, 2005, the debt facilities of Cortez Capital Corporation consisted of: - $75 million of Series D notes due May 15, 2013; - a $125 million short-term commercial paper program; and - a $125 million five-year committed revolving credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program). As of September 30, 2005, Cortez Capital Corporation had $100.1 million of commercial paper outstanding with an average interest rate of 3.6582%, the average interest rate on the Series D notes was 7.14%, and there were no borrowings under the credit facility. Red Cedar Gathering Company Debt In October 1998, Red Cedar Gathering Company sold $55 million in aggregate principal amount of Senior Notes due October 31, 2010. The $55 million was sold in 10 different notes in varying amounts with identical terms. The Senior Notes are collateralized by a first priority lien on the ownership interests, including our 49% ownership interest, in Red Cedar Gathering Company. The Senior Notes are also guaranteed by us and the other owner of Red Cedar Gathering Company jointly and severally. The principal is to be repaid in seven equal installments beginning on October 31, 2004 and ending on October 31, 2010. As of September 30, 2005, $47.1 million in principal amount of notes were outstanding. 38 Nassau County, Florida Ocean Highway and Port Authority Debt Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the State of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals LLC, the operator of the port facilities. In July 2002, we acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement. In December 2002, we issued a $28 million letter of credit under our credit facilities and the former letter of credit guarantee was terminated. Principal payments on the bonds are made on the first of December each year and reductions are made to the letter of credit. As of September 30, 2005, the value of this letter of credit outstanding under our credit facility was $25.9 million. Certain Relationships and Related Transactions In conjunction with our acquisition of Natural Gas Pipelines assets from KMI on December 31, 1999, December 31, 2000, and November 1, 2004, KMI became a guarantor of approximately $733.5 million of our debt. KMI would be obligated to perform under this guarantee only if we and/or our assets were unable to satisfy our obligations. For additional information regarding our debt facilities, see Note 9 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2004. 8. Partners' Capital As of September 30, 2005 and December 31, 2004, our partners' capital consisted of the following limited partner units:
September 30, December 31, 2004 2005 ----------- ----------- Common units.................. 154,403,326 147,537,908 Class B units................. 5,313,400 5,313,400 i-units....................... 56,986,081 54,157,641 ----------- ----------- Total limited partner units. 216,702,807 207,008,949 =========== ===========
The total limited partner units represent our limited partners' interest and an effective 98% economic interest in us, exclusive of our general partner's incentive distribution rights. Our general partner has an effective 2% interest in us, excluding its incentive distribution rights. As of September 30, 2005, our common unit totals consisted of 140,047,591 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner. As of December 31, 2004, our common unit total consisted of 133,182,173 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. On August 16, 2005, we issued, in a public offering, 5,000,000 of our common units at a price of $51.25 per unit, less commissions and underwriting expenses. At the time of the offering, we granted the underwriters a 30-day option to purchase up to an additional 750,000 common units from us on the same terms and conditions, and pursuant to this option, we issued an additional 750,000 common units on September 9, 2005 upon exercise of this option. After commissions and underwriting expenses, we received net proceeds of $283.6 million for the issuance of these 5,750,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program. On both September 30, 2005 and December 31, 2004, our Class B units were held entirely by KMI and our i-units were held entirely by KMR. All of our Class B units were issued to KMI in December 2000. The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. 39 Our i-units are a separate class of limited partner interests in us. All of our i-units are owned by KMR and are not publicly traded. In accordance with its limited liability company agreement, KMR's activities are restricted to being a limited partner in us, and controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR's limited liability company agreement, the number of outstanding KMR shares and the number of i-units will at all times be equal. Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common unit. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We will not distribute the cash to the holders of our i-units but will retain the cash for use in our business. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, KMR received a distribution of 909,009 i-units from us on August 12, 2005. These additional i-units distributed were based on the $0.78 per unit distributed to our common unitholders on that date. For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. Incentive distributions allocated to our general partner are determined by the amount quarterly distributions to unitholders exceed certain specified target levels. Our distribution of $0.78 per unit paid on August 12, 2005 for the second quarter of 2005 required an incentive distribution to our general partner of $115.7 million. Our distribution of $0.71 per unit paid on August 13, 2004 for the second quarter of 2004 required an incentive distribution to our general partner of $94.9 million. The increased incentive distribution to our general partner paid for the second quarter of 2005 over the distribution paid for the second quarter of 2004 reflects the increase in the amount distributed per unit as well as the issuance of additional units. Our declared distribution for the third quarter of 2005 of $0.79 per unit will result in an incentive distribution to our general partner of approximately $121.5 million. This compares to our distribution of $0.73 per unit and incentive distribution to our general partner of approximately $99.1 million for the third quarter of 2004. 9. Comprehensive Income SFAS No. 130, "Accounting for Comprehensive Income," requires that enterprises report a total for comprehensive income. For the three and nine months ended September 30, 2005, the difference between our net income and our comprehensive income resulted from unrealized gains or losses on derivatives utilized for hedging purposes and from foreign currency translation adjustments. For the three and nine months ended September 30, 2004, the only difference between our net income and our comprehensive income was the unrealized gain or loss on derivatives utilized for hedging purposes. For more information on our hedging activities, see Note 10. Our total comprehensive income is as follows (in thousands): 40
Three Months Ended Nine Months Ended September 30, September 30, ------------------------ ---------------------- 2005 2004 2005 2004 ---------- --------- ----------- ---------- Net income.................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314 Foreign currency translation adjustments ..................... 8 - (596) - Change in fair value of derivatives used for hedging purposes. (259,826) (268,212) (1,016,695) (504,234) Reclassification of change in fair value of derivatives to net income 141,361 45,002 287,032 118,214 ---------- --------- ----------- ---------- Comprehensive income/(loss)................................. $ 126,930 $ (5,868) $ (39,425) $ 218,294 ========== ========= =========== ==========
10. Risk Management Hedging Activities Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. We use energy financial instruments to reduce our risk of changes in the prices of natural gas, natural gas liquids and crude oil markets (and carbon dioxide to the extent contracts are tied to crude oil prices) as discussed below. These risk management instruments are also called derivatives, which are defined as a financial instrument or other contract which derives its value from the value of some other financial instrument or variable. The value of a derivative (for example, options, swaps, futures contracts, etc.) is a function of the underlying (for example, a specified interest rate, commodity price, foreign exchange rate, or other variable) and the notional amount (for example, a number of currency units, shares, commodities, or other units specified in a derivative instrument), and while the value of the underlying changes due to changes in market conditions, the notional amount remains constant throughout the life of the derivative contract. Current accounting standards require derivatives to be reflected as assets or liabilities at their fair market values and the fair value of our risk management instruments reflects the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. We have available market quotes for substantially all of the financial instruments that we use, including: commodity futures and options contracts, fixed-price swaps, and basis swaps. Pursuant to our management's approved risk management policy, we are to engage in these activities as a hedging mechanism against price volatility associated with: - pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; - pre-existing or anticipated physical carbon dioxide sales that have pricing tied to crude oil prices; - natural gas purchases; and - system use and storage. Our risk management activities are primarily used in order to protect our profit margins and our risk management policies prohibit us from engaging in speculative trading. Commodity-related activities of our risk management group are monitored by our risk management committee, which is charged with the review and enforcement of our management's risk management policy. Specifically, our risk management committee is a separately designated standing committee comprised of 15 executive-level employees of KMI or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Our risk management committee is chaired by our Chief Financial Officer and is charged with the following three responsibilities: - establish and review risk limits consistent with our risk tolerance philosophy; - recommend to the audit committee of our general partner's delegate any changes, modifications, or amendments to our trading policy; and 41 - address and resolve any other high-level risk management issues. Our derivatives hedge the commodity price risks derived from our normal business activities, which include the sale of natural gas, natural gas liquids, oil and carbon dioxide, and these derivatives have been designated by us as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently is reclassified into earnings when the hedged forecasted transaction affects earnings. If the transaction results in an asset or liability, amounts in accumulated other comprehensive income should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc. To be considered effective, changes in the value of the derivative or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative instrument is reported in earnings immediately. In addition, in conjunction with the purchase of exchange-traded derivatives or when the market value of our derivatives with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing funds in margin accounts (reported as "Restricted deposits" in the accompanying interim consolidated balance sheet). As of September 30, 2005, we had four outstanding letters of credit totaling $609 million in support of our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids, crude oil and carbon dioxide. The gains and losses that are included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets are primarily related to the derivative instruments associated with our commodity market risk hedging activities, and these gains and losses are reclassified into earnings as the hedged sales and purchases take place. Approximately $406.1 million of the Accumulated other comprehensive loss balance of $1,187.6 million as of September 30, 2005 is expected to be reclassified into earnings during the next twelve months. During the nine months ended September 30, 2005 and 2004, we reclassified $287.0 million and $118.2 million, respectively, of Accumulated other comprehensive loss into earnings. The reclassification of Accumulated other comprehensive loss into earnings during the nine months ended September 30, 2005 reduced the Accumulated other comprehensive loss balance of $457.3 million as of December 31, 2004. None of the reclassification of Accumulated other comprehensive loss into earnings during the first nine months of 2005 or 2004 resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period, but rather resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred). As discussed above, the ineffective portion of the gain or loss on a cash flow hedging instrument is required to be recognized currently in earnings. Accordingly, we recognized a loss of $1.9 million during the third quarter of 2005 and a loss of $2.3 million during the first nine months of 2005 as a result of ineffective hedges, and we recognized a minimal amount (less than $0.1 million) of gain or loss during the third quarter and the first nine months of 2004 as a result of ineffective hedges. All gains and losses recognized as a result of ineffective hedges are reported within the captions "Natural gas sales" and "Gas purchases and other costs of sales" in our accompanying consolidated statements of income. For each of the nine months ended September 30, 2005 and 2004, we did not exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness. The differences between the current market value and the original physical contracts value associated with our commodity market hedging activities are included within "Other current assets", "Accrued other current liabilities", "Deferred charges and other assets" and "Other long-term liabilities and deferred credits" in our accompanying consolidated balance sheets. The following table summarizes the net fair value of our energy financial instruments associated with our commodity market risk management activities and included on our accompanying consolidated balance sheets as of September 30, 2005 and December 31, 2004 (in thousands): 42
September 30, December 31, 2005 2004 ------------------------------ Derivatives-net asset/(liability) Other current assets............................... $ 201,439 $ 41,010 Deferred charges and other assets.................. 81,264 17,408 Accrued other current liabilities.................. (617,259) (218,967) Other long-term liabilities and deferred credits... $ (871,110) $ (309,035)
Our over-the-counter swaps and options are with a number of parties, who principally have investment grade credit ratings. We both owe money and are owed money under these financial instruments; however, as of both September 30, 2005 and December 31, 2004, we were essentially in a net payable position and had virtually no amounts owed to us from other parties. In addition, defaults by counterparties under over-the-counter swaps and options could expose us to additional commodity price risks in the event that we are unable to enter into replacement contracts for such swaps and options on substantially the same terms. Alternatively, we may need to pay significant amounts to the new counterparties to induce them to enter into replacement swaps and options on substantially the same terms. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. Certain of our business activities expose us to foreign currency fluctuations. However, due to the limited size of this exposure, we do not believe the risks associated with changes in foreign currency will have a material adverse effect on our business, financial position, results of operations or cash flows. Interest Rate Swaps In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. As of September 30, 2005 and December 31, 2004, we were a party to interest rate swap agreements with notional principal amounts of $2.1 billion and $2.3 billion, respectively. We entered into these agreements for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations. As of September 30, 2005, a notional principal amount of $2.1 billion of these agreements effectively converts the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread: - $200 million principal amount of our 5.35% senior notes due August 15, 2007; - $250 million principal amount of our 6.30% senior notes due February 1, 2009; - $200 million principal amount of our 7.125% senior notes due March 15, 2012; - $250 million principal amount of our 5.0% senior notes due December 15, 2013; - $200 million principal amount of our 5.125% senior notes due November 15, 2014; - $300 million principal amount of our 7.40% senior notes due March 15, 2031; - $200 million principal amount of our 7.75% senior notes due March 15, 2032; - $400 million principal amount of our 7.30% senior notes due August 15, 2033; and - $100 million principal amount of our 5.80% senior notes due March 15, 2035. These swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes, therefore, as of September 30, 2005, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035. These interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. SFAS No. 133 43 designates derivatives that hedge a recognized asset or liability's exposure to changes in their fair value as fair value hedges and the gain or loss on fair value hedges are to be recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of that accounting is to reflect in earnings the extent to which the hedge is not effective in achieving offsetting changes in fair value. The swap agreements related to our 7.40% senior notes contain mutual cash-out provisions at the then-current economic value every seven years. The swap agreements related to our 7.125% senior notes contain cash-out provisions at the then-current economic value in March 2009. The swap agreements related to our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out provisions at the then-current economic value every five or seven years. As of December 31, 2004, we also had swap agreements that effectively converted the interest expense associated with $100 million of our variable rate debt to fixed rate debt. Half of these agreements, converting $50 million of our variable rate debt to fixed rate debt, matured on August 1, 2005, and the remaining half matured on September 1, 2005. These swaps were designated as a cash flow hedge of the risk associated with changes in the designated benchmark interest rate (in this case, one-month LIBOR) related to forecasted payments associated with interest on an aggregate of $100 million of our portfolio of commercial paper. Our interest rate swaps meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments or fixed rate payments under the swaps. Interest expense is accrued monthly and paid semi-annually. The differences between fair value and the original carrying value associated with our interest rate swap agreements are included within "Deferred charges and other assets" and "Other long-term liabilities and deferred credits" in our accompanying consolidated balance sheets. The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is recognized as "Market value of interest rate swaps" on our accompanying consolidated balance sheets. The following table summarizes the net fair value of our interest rate swap agreements associated with our interest rate risk management activities and included on our accompanying consolidated balance sheets as of September 30, 2005 and December 31, 2004 (in thousands):
September 30, December 31, 2005 2004 ------------ ------------ Derivatives-net asset/(liability) Deferred charges and other assets................. $ 121,759 $ 132,210 Other long-term liabilities and deferred credits.. (6,706) (2,057) --------- ---------- Market value of interest rate swaps............. $ 115,053 $ 130,153 ========= ==========
We are exposed to credit related losses in the event of nonperformance by counterparties to these interest rate swap agreements. While we enter into derivative transactions primarily with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk. 11. Reportable Segments We divide our operations into four reportable business segments: - Products Pipelines; - Natural Gas Pipelines; 44 - CO2; and - Terminals. We evaluate performance principally based on each segments' earnings before depreciation, depletion and amortization, which exclude general and administrative expenses, third-party debt costs and interest expense, unallocable interest income and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies. Our Products Pipelines segment derives its revenues primarily from the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the transmission, storage, gathering and sale of natural gas. Our CO2 segment derives its revenues primarily from the production and sale of crude oil from fields in the Permian Basin of West Texas and from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals. Financial information by segment follows (in thousands):
Three Months Ended Nine Months Ended September 30, September 30, 2005 2004 2005 2004 -------------- -------------- -------------- ------------- Revenues Products Pipelines................................. $ 181,903 $ 160,867 $ 527,818 $ 475,187 Natural Gas Pipelines.............................. 2,108,788 1,598,554 5,198,337 4,591,293 CO2................................................ 163,079 121,777 488,271 337,935 Terminals.......................................... 177,484 133,461 515,115 389,682 ------------- ------------- ------------- ------------- Total consolidated revenues........................ $ 2,631,254 $ 2,014,659 $ 6,729,541 $ 5,794,097 ============= ============= ============= ============= Operating expenses(a) Products Pipelines................................. $ 60,613 $ 46,489 $ 169,739 $ 135,792 Natural Gas Pipelines.............................. 1,996,737 1,498,030 4,863,524 4,301,857 CO2................................................ 48,546 43,331 152,389 123,620 Terminals.......................................... 94,318 63,943 271,470 188,336 ------------- ------------- ------------- ------------- Total consolidated operating expenses.............. $ 2,200,214 $ 1,651,793 $ 5,457,122 $ 4,749,605 ============= ============= ============= ============= Depreciation, depletion and amortization Products Pipelines................................. $ 19,849 $ 17,951 $ 59,071 $ 52,751 Natural Gas Pipelines.............................. 15,205 13,191 45,779 38,959 CO2................................................ 34,658 30,465 111,822 86,583 Terminals.......................................... 15,644 10,607 41,972 31,330 ------------- ------------- ------------- ------------- Total consol. depreciation, depletion and amortization $ 85,356 $ 72,214 $ 258,644 $ 209,623 ============= ============= ============= ============= Earnings from equity investments Products Pipelines................................. $ 6,256 $ 7,658 $ 21,706 $ 21,610 Natural Gas Pipelines.............................. 8,705 5,280 25,733 14,558 CO2................................................ 5,533 7,711 21,932 25,552 Terminals.......................................... 18 (4) 51 3 ------------- ------------- ------------- ------------- Total consolidated equity earnings................. $ 20,512 $ 20,645 $ 69,422 $ 61,723 ============= ============= ============= ============= Amortization of excess cost of equity investments Products Pipelines................................. $ 832 $ 819 $ 2,512 $ 2,461 Natural Gas Pipelines.............................. 70 70 208 208 CO2................................................ 505 505 1,513 1,513 Terminals.......................................... - - - - ------------- ------------- ------------- ------------- Total consol. amortization of excess cost of $ 1,407 $ 1,394 $ 4,233 $ 4,182 investments ============= ============= ============= =============
45
Three Months Ended Nine Months Ended September 30, September 30, 2005 2004 2005 2004 -------------- -------------- -------------- ------------- Interest income Products Pipelines................................. $ 1,147 $ 930 $ 3,445 $ 930 Natural Gas Pipelines.............................. 193 - 530 - CO2................................................ - - - - Terminals.......................................... - - - - ------------- ------------- ------------- ------------- Total segment interest income...................... 1,340 930 3,975 930 Unallocated interest income........................ 109 236 374 713 ------------- ------------- ------------- ------------- Total consolidated interest income................. $ 1,449 $ 1,166 $ 4,349 $ 1,643 ============= ============= ============= ============= Other, net - income (expense) Products Pipelines................................. $ 633 $ 171 $ 998 $ 936 Natural Gas Pipelines.............................. 1,367 29 1,509 1,155 CO2................................................ (6) 10 (6) 42 Terminals.......................................... 886 (61) (293) (306) ------------- ------------- ------------- ------------- Total segment other, net - income (expense)........ 2,880 149 2,208 1,827 Loss from early extinguishment of debt............. - - - (1,424) ------------- ------------- ------------- ------------- Total consolidated Other, net - income (expense)... $ 2,880 $ 149 $ 2,208 $ 403 ============= ============= ============= ============= Income tax benefit (expense) Products Pipelines................................. $ (2,171) $ (2,784) $ (8,209) $ (8,968) Natural Gas Pipelines.............................. (361) (622) (1,899) (1,395) CO2................................................ (151) (49) (263) (96) Terminals.......................................... (2,372) (2,285) (9,874) (5,003) ------------- ------------- ------------- ------------- Total consolidated income tax benefit (expense).... $ (5,055) $ (5,740) $ (20,245) $ (15,462) ============== ============== ============== ============== Segment earnings Products Pipelines................................. $ 106,474 $ 101,583 $ 314,436 $ 298,691 Natural Gas Pipelines.............................. 106,680 91,950 314,699 264,587 CO2................................................ 84,746 55,148 244,210 151,717 Terminals.......................................... 66,054 56,561 191,557 164,710 ------------- ------------- ------------- ------------- Total segment earnings(b).......................... 363,954 305,242 1,064,902 879,705 Interest and corporate administrative expenses(c).. (118,567) (87,900) (374,068) (275,391) ------------- ------------- ------------- ------------- Total consolidated net income...................... $ 245,387 $ 217,342 $ 690,834 $ 604,314 ============= ============= ============= ============= Segment earnings before depreciation, depletion, amortization And amortization of excess cost of equity investments(d) Products Pipelines................................. $ 127,155 $ 120,353 $ 376,019 $ 353,903 Natural Gas Pipelines.............................. 121,955 105,211 360,686 303,754 CO2................................................ 119,909 86,118 357,545 239,813 Terminals.......................................... 81,698 67,168 233,529 196,040 ------------- ------------- ------------- ------------- Total segment earnings before DD&A................. 450,717 378,850 1,327,779 1,093,510 Total consol. depreciation, depletion and (85,356) (72,214) (258,644) (209,623) amortization.......................................... Total consol. amortization of excess cost of (1,407) (1,394) (4,233) (4,182) investments........................................... Interest and corporate administrative expenses..... (118,567) (87,900) (374,068) (275,391) ------------- ------------- ------------- ------------- Total consolidated net income ..................... $ 245,387 $ 217,342 $ 690,834 $ 604,314 ============= ============= ============= ============= Capital expenditures Products Pipelines................................. $ 82,592 $ 104,154 $ 180,309 $ 171,116 Natural Gas Pipelines.............................. 31,707 23,831 64,854 77,904 CO2................................................ 92,603 65,423 219,545 224,630 Terminals.......................................... 48,675 32,298 132,478 91,581 ------------- ------------- ------------- ------------- Total consolidated capital expenditures(e)......... $ 255,577 $ 225,706 $ 597,186 $ 565,231 ============= ============= ============= =============
September 30, December 31, 2005 2004 ------------- -------------- Assets Products Pipelines........................... $ 3,826,238 $ 3,651,657 Natural Gas Pipelines........................ 4,162,390 3,691,457 CO2.......................................... 1,796,313 1,527,810 Terminals.................................... 1,999,351 1,576,333 ------------- -------------- Total segment assets......................... 11,784,292 10,447,257 Corporate assets(f).......................... 40,357 105,685 ------------- -------------- Total consolidated assets.................... $ 11,824,649 $ 10,552,942 ============= ==============
46 (a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses, depreciation, depletion and amortization, and amortization of excess cost of equity investments. (c) Includes unallocated interest income, interest and debt expense, general and administrative expenses, minority interest expense and loss from early extinguishment of debt (2004 only). (d) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses. (e) Includes sustaining capital expenditures of $42,845 and $36,776 for the three months ended September 30, 2005 and 2004 respectively, and includes sustaining capital expenditures of $95,801 and $82,870 for the nine months ended September 30, 2005 and 2004, respectively. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. (f) Includes cash, cash equivalents, restricted deposits and certain unallocable deferred charges. We do not attribute interest and debt expense to any of our reportable business segments. For the three months ended September 30, 2005 and 2004, we reported (in thousands) total consolidated interest expense of $69,797 and $47,531, respectively. For the nine months ended September 30, 2005 and 2004, we reported (in thousands) total consolidated interest expense of $196,736 and $141,821, respectively. 12. Pensions and Other Post-retirement Benefits In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk Terminals, Inc. in 1998, we acquired certain liabilities for pension and post-retirement benefits. We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. We also provide the same benefits to former salaried employees of SFPP. Additionally, we will continue to fund these costs for those employees currently in the plan during their retirement years. SFPP's post-retirement benefit plan is frozen, and no additional participants may join the plan. The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement Plan. The benefits under this plan are based primarily upon years of service and final average pensionable earnings; however, benefit accruals were frozen as of December 31, 1998. Net periodic benefit costs for these plans include the following components (in thousands):
Other Post-retirement Benefits Three Months Ended September 30, Nine Months Ended September 30, 2005 2004 2005 2004 Net periodic benefit cost Service cost...................... $ 2 $ 28 $ 6 $ 84 Interest cost..................... 77 97 231 291 Amortization of prior service cost (29) (31) (87) (93) Actuarial gain.................... (127) (244) (381) (732) ------ ------ ------ ------ Net periodic benefit cost......... $ (77) $ (150) $ (231) $ (450) ====== ====== ====== ======
Our net periodic benefit cost for each of the first three quarters of 2005 was a credit of $77,000, which resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost, primarily related to the following: - there have been changes to the plan for both 2004 and 2005 which reduced liabilities, creating a negative prior service cost that is being amortized each year; and - there was a significant drop in 2004 in the number of retired participants reported as pipeline retirees by Burlington Northern Santa Fe, which holds a 0.5% special limited partner interest in SFPP, L.P. 47 As of September 30, 2005, we estimate our overall net periodic post-retirement benefit cost for the year 2005 will be an annual credit of approximately $0.3 million. This amount could change in the remaining months of 2005 if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. 13. Related Party Transactions Plantation Pipe Line Company We own a 51.17% equity interest in Plantation Pipe Line Company. An affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004, Plantation repaid a $10 million note outstanding and $175 million in outstanding commercial paper borrowings with funds of $190 million borrowed from its owners. We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership interest, in exchange for a seven year note receivable bearing interest at the rate of 4.72% per annum. As of December 31, 2004, the principal amount receivable from this note was $96.3 million. We included $2.2 million of this balance within "Accounts, notes and interest receivable, net-Related parties" on our consolidated balance sheet as of December 31, 2004, and we included the remaining $94.1 million balance within "Notes receivable-Related parties." In June 2005, Plantation paid to us $1.1 million in principal amount under the note, and as of September 30, 2005, the principal amount receivable from this note was $95.2 million. We included $2.2 million of this balance within "Accounts, notes and interest receivable, net-Related parties" on our consolidated balance sheet as of September 30, 2005, and we included the remaining $93.0 million balance within "Notes receivable-Related parties." Coyote Gas Treating, LLC We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise Field Services LLC owns the remaining 50% equity interest. We are the managing partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in outstanding borrowings under its 364-day credit facility with funds borrowed from its owners. We loaned Coyote $17.1 million, which corresponds to our 50% ownership interest, in exchange for a one-year note receivable bearing interest payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30, 2003, the note was extended for one year. On June 30, 2004, the term of the note was made month-to-month. As of both December 31, 2004 and September 30, 2005, we included the principal amount of $17.1 million related to this note within "Notes Receivable-Related parties" on our consolidated balance sheets. Red Cedar Gathering Company We own a 49% equity interest in the Red Cedar Gathering Company. Red Cedar is a joint venture, and the Southern Ute Indian Tribe owns the remaining 51% equity interest. On December 22, 2004, we entered into a $10 million unsecured revolving credit facility due July 1, 2005, with the Southern Ute Indian Tribe and us, as lenders, and Red Cedar, as borrower. Subject to the terms of the agreement, the lenders may severally, but not jointly, make advances to Red Cedar up to a maximum outstanding principal amount of $10 million. On April 1, 2005, the maximum outstanding principal amount was automatically reduced to $5 million. In January 2005, Red Cedar borrowed funds of $4 million from its owners pursuant to this credit agreement, and we loaned Red Cedar approximately $2.0 million, which corresponded to our 49% ownership interest. The interest on all advances made under this credit facility were calculated as simple interest on the combined outstanding balance of the credit agreement at 6% per annum based upon a 360 day year. In March 2005, Red Cedar paid the $4 million outstanding balance under this revolving credit facility, and the facility expired on July 1, 2005. 48 KM Insurance, Ltd. KM Insurance, Ltd. ("KMIL"), is a Bermuda insurance company and wholly-owned subsidiary of KMI. KMIL was formed during the second quarter of 2005 as a Class 2 Bermuda insurance company, the sole business of which is to issue policies for KMI and us to secure the deductible portion of our workers compensation, automobile liability, and general liability policies placed in the commercial insurance market. We accrue for the cost of insurance, which is included in the related party general and administrative expenses. 14. Regulatory Matters FERC Order No. 2004 On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate natural gas pipeline was required to file a compliance plan by that date and was required to be in full compliance with the Standards of Conduct by June 1, 2004. The primary change from existing regulation is to make such standards applicable to an interstate natural gas pipeline's interaction with many more affiliates (referred to as "energy affiliates"), including intrastate/Hinshaw natural gas pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or within a state boundary, is regulated by an agency of that state, and all the gas it transports is consumed within that state), processors and gatherers and any company involved in natural gas or electric markets (including natural gas marketers) even if they do not ship on the affiliated interstate natural gas pipeline. Local distribution companies are excluded, however, if they do not make sales to customers not physically attached to their system. The Standards of Conduct require, among other things, separate staffing of interstate pipelines and their energy affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an energy affiliate. Kinder Morgan Interstate Gas Transmission LLC filed for clarification and rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing, Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of energy affiliates. On February 19, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company filed exemption requests with the FERC. The pipelines seek a limited exemption from the requirements of Order No. 2004 for the purpose of allowing their affiliated Hinshaw and intrastate pipelines, which are subject to state regulation and do not make any sales to customers not physically attached to their system, to be excluded from the rule's definition of energy affiliate. Separation from these entities would be the most burdensome requirement of the new rules for us. On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the effective date of the new Standards of Conduct from June 1, 2004, to September 1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but provided further clarification or adjustment in several areas. The FERC continued the exemption for local distribution companies which do not make off-system sales, but clarified that the local distribution company exemption still applies if the local distribution company is also a Hinshaw pipeline. The FERC also clarified that a local distribution company can engage in certain sales and other energy affiliate activities to the limited extent necessary to support sales to customers located on its distribution system, and sales necessary to remain in balance under pipeline tariffs, without becoming an energy affiliate. The FERC declined to exempt natural gas producers. The FERC also declined to exempt natural gas intrastate and Hinshaw pipelines, processors and gatherers, but did clarify that such entities will not be energy affiliates if they do not participate in gas or electric commodity markets, interstate capacity markets (as capacity holder, agent or manager), or in financial transactions related to such markets. The FERC also clarified further the personnel and functions which can be shared by interstate natural gas pipelines and their energy affiliates, including senior officers and risk management personnel, and the permissible role of holding or parent companies and service companies. The FERC also clarified that day-to-day operating information can be shared by interconnecting entities. Finally, the FERC clarified that an interstate natural gas pipeline and its energy affiliate can discuss potential new interconnects to serve the energy affiliate, but subject to very onerous posting and record-keeping requirements. 49 On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company filed additional joint requests with the interstate natural gas pipelines owned by KMI asking for limited exemptions from certain requirements of FERC Order 2004 and asking for an extension of the deadline for full compliance with Order 2004 until 90 days after the FERC has completed action on the pipelines' various rehearing and exemption requests. These exemptions request relief from the independent functioning and information disclosure requirements of Order 2004. The exemption requests propose to treat as energy affiliates, within the meaning of Order 2004, two groups of employees: - individuals in the Choice Gas Commodity Group within KMI's retail operations; and - commodity sales and purchase personnel within our Texas intrastate natural gas operations. Order 2004 regulations governing relationships between interstate pipelines and their energy affiliates would apply to relationships with these two groups. Under these proposals, certain critical operating functions could continue to be shared. On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC extended the effective date of the new Standards of Conduct from September 1, 2004 to September 22, 2004. Also in this order, among other actions, the FERC denied the request for rehearing made by the interstate pipelines of KMI and us to clarify the applicability of the local distribution company and parent company exemptions to them. In addition, the FERC denied the interstate pipelines' request for a 90 day extension of time to comply with Order 2004. On September 20, 2004, the FERC issued an order which conditionally granted the July 21, 2004 joint requests for limited exemptions from the requirements of the Standards of Conduct described above. In that order, FERC directed Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and the affiliated interstate pipelines owned by KMI to submit compliance plans regarding these exemptions within 30 days. These compliance plans were filed on October 19, 2004, and set out certain steps taken by us to assure that employees in the Choice Gas Commodity Group of KMI and the commodity sales and purchase personnel of our Texas intrastate organizations do not have access to restricted interstate natural gas pipeline information or receive preferential treatment as to interstate natural gas pipeline services. The FERC will not enforce compliance with the independent functioning requirement of the Standards of Conduct as to these employees until 30 days after it acts on these compliance filings. In all other respects, we were required to comply with the Standards of Conduct as of September 22, 2004. We have implemented compliance with the Standards of Conduct as of September 22, 2004, subject to the exemptions described in the prior paragraph. Compliance includes, among other things, the posting of compliance procedures and organizational information for each interstate pipeline on its Internet website, the posting of discount and tariff discretion information and the implementation of independent functioning for energy affiliates not covered by the prior paragraph (electric and gas gathering, processing or production affiliates). On December 21, 2004, the FERC issued Order No. 2004-C. In this order, the FERC granted rehearing on certain issues and also clarified certain provisions in the previous FERC 2004 orders. The primary impact on us from Order 2004-C is the granting of rehearing and allowing local distribution companies to participate in hedging activity related to on-system sales and still qualify for exemption from being an energy affiliate. By an order issued on April 19, 2005, the FERC accepted the compliance plans filed by us without modification, but subject to further amplification and clarification as to the intrastate group in three areas: - further description and explanation of the information or events relating to intrastate pipeline business that the shared transmission function personnel may discuss with our commodity sales and purchase personnel within our Texas intrastate natural gas operations; - additional posting of organizational information about the commodity sales and purchase personnel within our Texas intrastate natural gas operations; and 50 - clarification that the president of our intrastate natural gas pipeline group has received proper training and will not be a conduit for improperly sharing transmission or customer information with our commodity sales and purchase personnel within our Texas intrastate natural gas operations. Our interstate pipelines made a compliance filing on May 18, 2005. FERC Policy statement re: Use of Gas Basis Differentials for Pricing On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, we will no longer be permitted to use commodity price indices to structure transactions on our FERC regulated natural gas pipelines. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. Moreover, in subsequent orders in individual pipeline cases, the FERC has allowed negotiated rate transactions using pricing indices so long as revenue is capped by the applicable maximum rate(s). Rehearing on this aspect of the Modification to Policy Statement has been sought by several pipelines, but the FERC has not yet acted on rehearing. Price indexed contracts currently constitute an insignificant portion of our contracts on our FERC regulated natural gas pipelines; consequently, we do not believe that this Modification to Policy Statement will have a material impact on our operations, financial results or cash flows. Accounting for Integrity Testing Costs On November 5, 2004, the FERC issued a Notice of Proposed Accounting Release that would require FERC jurisdictional entities to recognize costs incurred in performing pipeline assessments that are a part of a pipeline integrity management program as maintenance expense in the period incurred. The proposed accounting ruling was in response to the FERC's finding of diverse practices within the pipeline industry in accounting for pipeline assessment activities. The proposed ruling would standardize these practices. Specifically, the proposed ruling clarifies the distinction between costs for a "one-time rehabilitation project to extend the useful life of the system," which could be capitalized, and costs for an "on-going inspection and testing or maintenance program," which would be accounted for as maintenance and charged to expense in the period incurred. Comments, along with responses to specific questions posed by FERC concerning the Notice of Proposed Accounting Release, were due January 19, 2005. We filed our comments on January 19, 2005, asking the FERC to modify the accounting release to allow capitalization of pipeline assessment costs associated with projects involving 100 feet or more of pipeline being replaced or recoated (including discontinuous sections) and to adopt an effective date for the final rule which is no earlier than January 1, 2006. On June 30, 2005, the FERC issued an order providing guidance to the industry on accounting for costs associated with pipeline integrity management requirements. The order is effective prospectively from January 1, 2006. Under the order, the costs to be expensed include those to: - prepare a plan to implement the program; - identify high consequence areas; - develop and maintain a record keeping system; and - inspect affected pipeline segments. The costs of modifying the pipeline to permit in-line inspections, such as installing pig launchers and receivers, are to be capitalized, as are certain costs associated with developing or enhancing computer software or to add or replace other items of plant. The Interstate Natural Gas Association of America sought rehearing of the FERC's June 30, 2005 order. The FERC denied INGAA's request for rehearing on September 19, 2005. We are currently reviewing the effects of this 51 order on our financial statements; however, we do not believe that this order will have a material impact on our operations, financial results or cash flows. Selective Discounting On November 22, 2004, the FERC issued a notice of inquiry seeking comments on its policy of selective discounting. Specifically, the FERC is asking parties to submit comments and respond to inquiries regarding the FERC's practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons - when the discount is given to meet competition from another gas pipeline. Comments were filed by numerous entities, including Natural Gas Pipeline Company of America (a Kinder Morgan, Inc. affiliate), on March 2, 2005. Several reply comments have subsequently been filed. By an order issued on May 31, 2005, the FERC reaffirmed its existing policy on selective discounting by interstate pipelines without change. Several entities have filed for rehearing. Index of Customer Audit On July 14, 2005, the FERC commenced an audit of TransColorado Gas Transmission Company, as well as a number of other interstate gas pipelines, to test compliance with the FERC's requirements related to the filing and posting of the Index of Customers report. On September 21, 2005, the FERC's staff issued a draft audit report which cited two minor issues with TransColorado's Index of Customers filings and postings. Subsequently, on October 11, 2005, the FERC issued a final order which closed its examination, citing the minor issues contained in its draft report and approving the corrective actions planned or already taken by TransColorado. TransColorado has implemented corrective actions and has applied those actions to its most recent Index of Customer filing, dated October 1, 2005. No further compliance action is expected and TransColorado anticipates operating in compliance with applicable FERC rules regarding the filing and posting of its future Index of Customers reports. 15. Recent Accounting Pronouncements SFAS No. 123R In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No. 123, "Accounting for Stock-Based Compensation," and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following: - share-based payment awards result in a cost that will be measured at fair value on the awards' grant date, based on the estimated number of awards that are expected to vest. Compensation cost for awards that vest would not be reversed if the awards expire without being exercised; - when measuring fair value, companies can choose an option-pricing model that appropriately reflects their specific circumstances and the economics of their transactions; - companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects. Upon settlement of share-based payment awards, the tax effects will be recognized in the income statement or additional paid-in capital; and - public companies are allowed to select from three alternative transition methods - each having different reporting implications. In April 2005, both the FASB and the Securities and Exchange Commission decided to delay the effective date for public companies to implement SFAS No. 123R (revised 2004). The new Statement is now effective for public companies for annual periods beginning after June 15, 2005 (January 1, 2006, for us). We are currently reviewing the effects of this accounting Statement; however, we have not granted common unit options since May 2000 and we do not expect the adoption of this Statement to have any material effect on our consolidated financial statements. 52 FIN 47 In March 2005, the Financial Accounting Standards Board issued Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement Obligations--an interpretation of FASB Statement No. 143". This interpretation clarifies that the term "conditional asset retirement obligation" as used in SFAS No. 143, "Accounting for Asset Retirement Obligations," refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred-generally upon acquisition, construction, or development and (or) through the normal operation of the asset. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for us). We are currently reviewing the effects of this Interpretation. SFAS No. 154 In June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections." This Statement replaces Accounting Principles Board Opinion No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements." SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods' financial statements of a voluntary change in accounting principle unless it is impracticable. In contrast, APB No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. The FASB believes the provisions of SFAS No. 154 will improve financial reporting because its requirement to report voluntary changes in accounting principles via retrospective application, unless impracticable, will enhance the consistency of financial information between periods. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (January 1, 2006 for us). Earlier application is permitted for accounting changes and corrections of errors made occurring in fiscal years beginning after June 1, 2005. The Statement does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of this Statement. Adoption of this Statement will not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively. EITF 04-5 In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, "Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights." EITF 04-5 provides guidance for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership. 53 For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). We are currently reviewing the specific effects of this Issue. 54 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis of our financial condition and results of operations provides you with a narrative on our financial results. It contains a discussion and analysis of the results of operations for each segment of our business, followed by a discussion and analysis of our financial condition. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report), and (ii) our consolidated financial statements, related notes and management's discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2004. Critical Accounting Policies and Estimates Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible asset impairment charges, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. Further information about us and information regarding our accounting policies and estimates that we consider to be "critical" can be found in our Annual Report on Form 10-K for the year ended December 31, 2004. There have not been any significant changes in these policies and estimates during the nine months ended September 30, 2005. Results of Operations Consolidated
Three Months Ended Nine Months Ended September 30, September 30, ------------ ---------- 2005 2004 2005 2004 ---- ---- ---- ---- (In thousands) Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments Products Pipelines........................................... $ 127,155 $ 120,353 $ 376,019 $ 353,903 Natural Gas Pipelines........................................ 121,955 105,211 360,686 303,754 CO2.......................................................... 119,909 86,118 357,545 239,813 Terminals.................................................... 81,698 67,168 233,529 196,040 ----------- ----------- ----------- ----------- Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a) 450,717 378,850 1,327,779 1,093,510 Depreciation, depletion and amortization expense................. (85,356) (72,214) (258,644) (209,623) Amortization of excess cost of equity investments................ (1,407) (1,394) (4,233) (4,182) Interest and corporate administrative expenses(b)................ (118,567) (87,900) (374,068) (275,391) ----------- ----------- ----------- ------------ Net income....................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314 =========== =========== =========== ============
- ------- (a) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses. (b) Includes unallocated interest income, interest and debt expense, general and administrative expenses, minority interest expense and loss from early extinguishment of debt (2004 only). 55 Our consolidated net income for the quarterly period ending September 30, 2005 was $245.4 million ($0.57 per diluted unit), compared to $217.3 million ($0.59 per diluted unit) for the quarterly period ending September 30, 2004. Net income for the nine months ended September 30, 2005 was $690.8 million ($1.61 per diluted unit), compared to $604.3 million ($1.62 per diluted unit) for the first nine months of 2004. We earned total revenues of $2,631.3 million and $2,014.7 million, respectively, in the three month periods ended September 30, 2005 and 2004, and revenues of $6,729.5 million and $5,794.1 million, respectively, in the nine month periods ended September 30, 2005 and 2004. The increases in our net income in both the third quarter and first nine months of 2005 compared to the same prior year periods were broad-based, attributable to higher segment earnings from each of our four reportable business segments. Specifically, the increases were primarily due to: - higher earnings from our oil and gas producing activities, resulting from higher crude oil and natural gas processing plant liquids production volumes, higher industry price levels for both crude oil and natural gas processing plant liquids products, and higher third party carbon dioxide sales and transport volumes; - improved gross margin performance on our Texas intrastate natural gas pipelines, higher revenues from both natural gas interstate transportation and storage services, and higher earnings from our natural gas gathering equity investees; and - incremental earnings attributable to internal expansion projects and strategic acquisitions completed since the end of the third quarter of 2004. Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we look at each period's earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, as an important measure of our success in maximizing returns to our partners. We also use this measure of profit and loss internally for evaluating segment performance and deciding how to allocate resources to our business segments. In both the third quarter and first nine months of 2005, all four of our reportable business segments reported increases in earnings before depreciation, depletion and amortization compared to the same periods of 2004. Furthermore, we declared a cash distribution of $0.79 per unit for the third quarter of 2005 (an annualized rate of $3.16). This distribution is approximately 8% higher than the $0.73 per unit distribution we made for the third quarter of 2004. We expect to declare cash distributions of at least $3.13 per unit for 2005; however, no assurance can be given that we will be able to achieve this level of distribution. Third Quarter 2005 Hurricanes On August 29, 2005, Hurricane Katrina struck the United States' Gulf Coast causing wide-spread damage to residential and commercial real and personal property. The assets we operate that were impacted by the storm include the Plantation Pipe Line Company system, and several bulk and liquids terminal facilities located in the States of Louisiana and Mississippi. With regard to Plantation, a 3,100-mile refined petroleum products pipeline which serves the southeastern United States and is owned approximately 51% by us, the pipeline, equipment and storage tanks suffered no damage but service was suspended for several days due to local electricity outages. On September 1, 2005, we resumed limited service on the pipeline. On September 2, 2005, electricity was restored to all of the primary pump stations, and full service was resumed. With regard to our Terminals segment's Lower Mississippi River region, most of our owned terminal sites were minimally impacted and suffered no significant structural damage. However, our Port of New Orleans facility, located in Harvey, Louisiana, and our International Marine Terminals Partnership facility, located in Port Sulphur, Louisiana and owned 66 2/3% by us, incurred greater property damage. Both facilities have resumed limited service and further damage assessments are necessary and in process. At two third-party owned facilities which were damaged by Katrina, one located in DeLisle, Mississippi and the other in Chalmette, Louisiana, we provide contract handling services and other in-plant operations, and future activity at these two sites is dependent upon resumption of operations by the owners of the facilities. 56 On September 23, 2005, Hurricane Rita struck the Texas-Louisiana Gulf Coast causing minimal damage to our assets. However, both our Cypress Pipeline, which transports natural gas liquids from Mont Belvieu, Texas to Lake Charles, Louisiana, and our Gulf Coast liquids terminals facilities, which are located along the Houston Ship Channel and can store up to 18 million barrels of refined products and petrochemicals, were temporarily shut down, but resumed operations shortly thereafter. In addition, seven terminal sites included in our Texas Petcoke terminal region and which primarily handle petroleum coke temporarily ceased operations as a result of crude oil refineries being shut down prior to the storm. All of the terminals have either resumed service or will do so in coordination with the start up of the associated refineries located along the Texas-Louisiana border. Our Texas intrastate natural gas pipeline group also operated throughout the storm. During the storm, average daily transport volumes fell to about 50% of normal levels as a result of decreased demand from Gulf Coast industrial customers, and access to natural gas storage was impacted due to loss of electric power. But overall, only minor damage occurred to the operating facilities, and we expect the utilization of our intrastate system will continue to increase in conjunction with rising market demand for energy after the hurricane. We continue to evaluate the full effect of the storms on our operations and presently, we expect that the costs incurred as a result of the two hurricanes will be less than $10 million, including insurance deductibles and lost business at our terminal sites (but excluding lost revenues from decreased volumes transported on our pipelines). Essentially all losses related to the storms' impact were included in our third quarter 2005 results, and we do not believe that the resolution of any remaining matters will have a material adverse effect on our business, financial position, results of operations or cash flows. Products Pipelines
Three Months Ended Nine Months Ended September 30, September 30, ------------- ------------- 2005 2004 2005 2004 ---- ---- ---- ---- (In thousands, except operating statistics) Revenues................................................... $ 181,903 $ 160,867 $ 527,818 $ 475,187 Operating expenses(a)...................................... (60,613) (46,489) (169,739) (135,792) Earnings from equity investments........................... 6,256 7,658 21,706 21,610 Interest income and Other, net-income (expense)............ 1,780 1,101 4,443 1,866 Income taxes............................................... (2,171) (2,784) (8,209) (8,968) ----------- ----------- ----------- ----------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity 127,155 120,353 376,019 353,903 investments................................................ Depreciation, depletion and amortization expense........... (19,849) (17,951) (59,071) (52,751) Amortization of excess cost of equity investments.......... (832) (819) (2,512) (2,461) ----------- ----------- ----------- ----------- Segment earnings......................................... $ 106,474 $ 101,583 $ 314,436 $ 298,691 =========== =========== =========== =========== Gasoline (MMBbl)........................................... 117.5 118.1 344.4 344.7 Diesel fuel (MMBbl)........................................ 41.7 41.6 122.8 120.8 Jet fuel (MMBbl)........................................... 29.3 30.5 88.1 88.4 ----------- ----------- ----------- ----------- Total refined product volumes (MMBbl).................... 188.5 190.2 555.3 553.9 Natural gas liquids (MMBbl)................................ 8.4 10.2 26.1 31.1 ----------- ----------- ----------- ----------- Total delivery volumes (MMBbl)(b)........................ 196.9 200.4 581.4 585.0 =========== =========== =========== ===========
- ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes. Our Products Pipelines segment reported earnings before depreciation, depletion and amortization of $127.2 million on revenues of $181.9 million in the third quarter of 2005. This compares to earnings before depreciation, depletion and amortization of $120.4 million on revenues of $160.9 million in the third quarter of 2004. For the comparable nine month periods, the segment reported earnings before depreciation, depletion and amortization of $376.0 million on revenues of $527.8 million in 2005, and earnings before depreciation, depletion and amortization of $353.9 million on revenues of $475.2 million in 2004. The segment's overall $6.8 million (6%) increase in earnings before depreciation, depletion and amortization in the third quarter of 2005 versus the third quarter of 2004 included a $6.2 million increase in earnings before 57 depreciation, depletion and amortization from our Southeast product terminal operations, including incremental earnings of $3.4 million from the refined product terminal operations we acquired in November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC. The $2.8 million (78%) quarter-to-quarter increase in earnings before depreciation, depletion and amortization from the Southeast terminals owned during both third quarters was primarily due to higher product throughput revenues. We also earned quarter-to-quarter increases of $5.5 million (8%) and $1.4 million (13%), respectively, from our Pacific and CALNEV product pipeline operations. The increase from our Pacific operations was primarily revenue driven: revenues from refined petroleum product deliveries increased $6.3 million (10%) and terminal service revenues increased $1.5 million (7%). The increase in revenues from product deliveries was due to both a 2% increase in delivery volumes and an 8% increase in average tariff rates. The increase in tariffs was due to a FERC tariff index increase in July 2005 (a purchase price index adjustment), and an increase in North Line tariff rates associated with pipeline expansion that was completed since the end of the third quarter of 2004. The higher terminal revenues reflected incremental revenues from diesel lubricity-improving injection services that we began offering in May 2005. CALNEV's quarter-to-quarter increase in earnings before depreciation, depletion and amortization was also due to higher product delivery revenues and higher product terminal revenues. CALNEV's revenues from refined product deliveries increased $0.9 million (8%), due primarily to an over 4% increase in transportation volumes, and revenues from terminal operations increased $0.7 million (27%), as the increase in throughput led to increased terminaling and ethanol blending services. The segment's overall increase in earnings before depreciation, depletion and amortization in the third quarter of 2005 versus the third quarter of 2004 was partially offset by a $5.5 million (129%) decrease from our North System and a $1.2 million (13%) decrease from our operatorship of the Plantation Pipe Line Company. The decrease from our North System was primarily due to a $5.0 million loss recognized in September 2005 to account for differences between physical and book natural gas liquids inventory. We expect to resolve the inventory related issues during the fourth quarter of 2005, in which case there may be an additional charge. The quarter-to-quarter decrease in earnings before depreciation, depletion and amortization from Plantation was chiefly due to a $1.5 million (20%) decrease in equity earnings from our approximate 51% ownership interest. The decrease reflects lower overall net income earned by Plantation in the third quarter of 2005, due primarily to lower transportation revenues as a result of an almost 11% decrease in delivery volumes. The decrease in Plantation's delivery volumes was due to pipeline disruptions caused by power outages as a result of Hurricane Katrina, and decreased supply from some of the refineries that transport products on its system, due to damages sustained from Hurricanes Katrina and Dennis, both occurring in the third quarter of 2005. The segment's overall $22.1 million (6%) increase in earnings before depreciation, depletion and amortization in the first nine months of 2005 versus the first nine months of 2004, included a $16.6 million increase from our Southeast product terminal operations, which included incremental earnings of $16.1 million from the combined terminal operations we acquired from Charter in November 2004 and Exxon Mobil Corporation in March 2004. We also reported an $11.2 million (6%) increase from our Pacific operations, a $2.0 million (8%) increase attributable to our ownership interest in Plantation, and a $1.6 million (5%) increase from our CALNEV Pipeline. Partially offsetting the year-over-year increase in segment earnings before depreciation, depletion and amortization was a $6.0 million (43%) decrease in earnings from our North System and a $3.1 million (16%) decrease from our petroleum pipeline transmix processing operations. The increases in earnings before depreciation, depletion and amortization expenses for the comparative nine month periods from our Pacific operations and our CALNEV Pipeline were mainly related to increases in operating revenues of $19.1 million (8%) and $3.2 million (8%), respectively. The increases in revenues were driven by both higher mainline delivery revenues and higher product terminal revenues. The increase from Plantation was mainly due to the recognition, in 2005, of incremental interest income of $2.5 million on our long-term note receivable from Plantation. In July 2004, we loaned $97.2 million to Plantation to allow it to pay all of its outstanding credit facility and commercial paper borrowings and in exchange for this funding, we received a seven year note receivable bearing interest at the rate of 4.72% per annum. The year-over-year decrease in earnings before depreciation, depletion and amortization from our North System was primarily due to the $5.0 million inventory reconciliation reserve taken in the third quarter of 2005, as discussed above, and to higher natural gas liquids storage expenses related to a new contract agreement entered into in April 58 2004. The year-to-date decrease in earnings from our transmix operations was due to both lower revenues and lower other income. The decrease in revenues was due to a 9% decrease in processing volumes, largely resulting from the disallowance, beginning in July 2004, of methyl tertiary-butyl ether (MTBE) blended transmix in the State of Illinois. The decrease in other income was due to a $0.9 million benefit taken from the reversal of certain short-term liabilities in the second quarter of 2004. Revenues for the segment increased $21.0 million (13%) in the third quarter of 2005 compared to the third quarter of 2004. For the comparative nine month periods, revenues increased $52.6 million (11%) in 2005 versus 2004. The quarter-to-quarter increase in segment revenues included incremental revenues of $9.5 million from our Southeast terminals, including $6.7 million attributable to the Charter terminals we acquired since the end of the third quarter of 2004. The remaining $2.8 million increase in revenues from our Southeast terminal operations was largely attributable to higher product throughput revenues, with significant contributions coming from our Greensboro, North Carolina and Newington, Virginia facilities. Other quarter-to-quarter increases in revenues include the combined $9.4 million (10%) increase from our Pacific operations and CALNEV Pipeline, as discussed above, and a $1.3 million (14%) increase from our Central Florida Pipeline, driven by a 14% increase in product delivery volumes in the third quarter of 2005. For Central Florida, the increase in volumes in 2005 was largely due to hurricane-related pipeline disruptions in the State of Florida during the third quarter of 2004. The increase in segment revenues between the comparable nine month periods included a $29.1 million increase from our Southeast terminals, including $28.4 million of incremental revenues from the terminals acquired since March 2004. Other year-over-year increases in revenues include a $19.1 million (8%) increase from our Pacific operations, a $3.2 million (8%) increase from our CALNEV Pipeline, and a $2.8 million (10%) increase from our Central Florida Pipeline. The overall increase in segment revenues was partially offset by a $2.0 million (8%) decrease from our transmix processing operations, as described above. Pacific's increase in revenues in the first nine months of 2005 relative to 2004 included increases of $14.9 million (8%) from mainline delivery volumes and $4.2 million (7%) from incremental terminal revenues. The increase from refined product deliveries was primarily due to an almost 7% increase in average tariff rates, and the increase from terminal revenues was due to higher product storage, injection and blending services. The higher tariff rates included both the Federal Energy Regulatory Commission approved 2004 annual indexed interstate tariff increase and a requested rate increase with the California Public Utility Commission. In November 2004, we filed an application with the CPUC requesting a $9 million increase in existing intrastate transportation rates to reflect the in-service date of our $95 million North Line expansion project. Pursuant to CPUC regulations, this increase automatically became effective as of December 22, 2004, but is being collected subject to refund, pending resolution of protests to the application by certain shippers. The CPUC may resolve the matter in the fourth quarter of 2005. The $3.2 million year-over-year increase in CALNEV's revenues consists of a $1.5 million (5%) increase from refined product deliveries, and a $1.7 million (21%) increase from expanded terminaling and ethanol blending operations. The $2.8 million (10%) increase in Central Florida's revenues in the first nine months of 2005 versus the same period in 2004, was due to an 11% increase in transport volumes, which more than offset a slight (1%) drop in the average tariff per barrel moved. For the third quarter of 2005, total delivery volumes of refined products were down 0.9% compared to the third quarter of 2004, with increases on Pacific, Central Florida and CALNEV offset by a decrease on Plantation. The decrease from Plantation was primarily due to the pipeline's temporary shutdown caused by Hurricane Katrina, which contributed to a 10.3% decrease in gasoline delivery volumes (gasoline deliveries account for approximately 65% of the total fuel volumes transported by the pipeline). Excluding Plantation, segment deliveries of gasoline, diesel fuel and jet fuel increased 4.2%, 3.6% and 0.4%, respectively, in the third quarter of 2005 compared to the third quarter of 2004. Quarter-to-quarter deliveries of natural gas liquids were down 17.6% due to low demand for propane on the North System, primarily due to a slower grain drying season in 2005, and to the hurricane-related closure of a petrochemical plant in Lake Charles, Louisiana that is served by our Cypress Pipeline. The segment's operating expenses increased $14.1 million (30%) in the third quarter of 2005, compared to the third quarter of 2004, and increased $33.9 million (25%) in the first nine months of 2005, compared to the first nine months of 2004. Both periodic increases included the North System's $5.0 million third quarter 2005 product 59 inventory reconciliation reserve adjustment discussed above. Other items included in the increase in operating expenses in the third quarter of 2005 versus the third quarter of 2004 are as follows: - a $3.3 million increase from the Southeast terminal operations we acquired in November 2004; - a $2.6 million (14%) increase from our Pacific operations, due primarily to higher overall operating, maintenance and labor expenses associated with increased transportation volumes and terminal operations; - a $0.9 million (43%) increase from our Central Florida Pipeline operations, due primarily to additional expense accruals related to a pipeline release occurring in September 2005; and - a $0.8 million (13%) increase from Plantation Pipe Line, due primarily to higher labor expenses following timing differences that resulted in an additional pay period in the third quarter of 2005 versus the third quarter of 2004. Other items included in the increase in operating expenses in the first nine months of 2005 versus the first nine months of 2004 are as follows: - a $12.3 million increase from the Southeast terminal operations we acquired since March 2004; - a $9.6 million (15%) increase from our combined Pacific and CALNEV Pipeline operations, due primarily to higher repair, maintenance and labor expenses associated with line wash-outs, clean-up work, inspections, and environmental issues; - a $1.9 million (19%) increase from our 49.8% proportionate interest in the Cochin pipeline system, due primarily to higher labor and outside services associated with additional health, safety and security work; and - a $1.3 million (10%) increase from our West Coast terminal operations, due primarily to higher property tax expenses as a result of expense reversals taken in the second quarter of 2004 pursuant to favorable property reassessments. In the third quarter of 2005, the segment's earnings from equity investments decreased $1.4 million (18%) from the equity earnings reported in the third quarter of 2004. The decrease was primarily due to the $1.5 million (20%) decrease in equity earnings from our 51% ownership interest in Plantation Pipe Line Company, discussed above. For the comparative nine month periods, the segment's equity earnings were essentially flat, as higher year-over-year earnings from our 50% investment in the Heartland Pipeline Company were largely offset by lower equity earnings from our investment in Plantation. The segment's income from allocable interest income and other income and expense items increased $0.7 million (62%) in the third quarter of 2005 versus the third quarter of 2004. The increase was mainly due to higher property sales and miscellaneous discounts earned by our West Coast terminal and Pacific operations. For the comparative nine month periods, income from interest and other items increased $2.6 million (138%) in 2005 versus 2004. The increase primarily relates to the incremental interest income of $2.5 million on our long-term note receivable from Plantation, as discussed above. The segment's income tax expenses decreased $0.6 million (22%) in the third quarter of 2005 compared to the third quarter of 2004, primarily due to the lower net income of Plantation Pipe Line Company. For the comparative nine month periods, income tax expenses decreased $0.8 million (8%) in 2005, due primarily to lower pre-tax earnings from the Canadian operations of the Cochin pipeline system, largely attributable to a decrease in propane demand as a result of warmer winter weather in 2005 versus 2004. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of equity investments, increased $1.9 million (10%) in the third quarter of 2005, and $6.4 million (12%) in the first nine 60 months of 2005, when compared to the same periods last year. The increases were primarily due to incremental depreciation charges associated with our Pacific operations and to the inclusion of additional depreciation charges on the Southeast terminal assets that we have owned for the entire nine months of 2005. The increases from our Pacific operations related to higher depreciable costs as a result of the capital spending we have made since the end of the third quarter of 2004. Natural Gas Pipelines
Three Months Ended Nine Months Ended September 30, September 30, --------------------------- --------------------------- 2005 2004 2005 2004 ---- ---- ---- ---- (In thousands, except operating statistics) Revenues................................................... $ 2,108,788 $ 1,598,554 $ 5,198,337 $ 4,591,293 Operating expenses(a)...................................... (1,996,737) (1,498,030) (4,863,524) (4,301,857) Earnings from equity investments........................... 8,705 5,280 25,733 14,558 Interest income and Other, net-income (expense)............ 1,560 29 2,039 1,155 Income taxes............................................... (361) (622) (1,899) (1,395) ------------ ------------ ------------ ------------ Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity 121,955 105,211 360,686 303,754 investments................................................ Depreciation, depletion and amortization expense........... (15,205) (13,191) (45,779) (38,959) Amortization of excess cost of equity investments.......... (70) (70) (208) (208) ------------ ------------ ------------ ------------ Segment earnings......................................... $ 106,680 $ 91,950 $ 314,699 $ 264,587 ============ ============ ============ ============ Natural gas transport volumes (Trillion Btus)(b)........... 359.4 361.4 1,004.5 1,007.1 ============ ============ ============ ============ Natural gas sales volumes (Trillion Btus)(c)............... 239.3 260.9 688.6 748.8 ============ ============ ============ ============
- ---------- (a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate natural gas pipeline group, Trailblazer and TransColorado pipeline volumes. TransColorado volumes are included for all periods (acquisition date November 1, 2004). (c) Represents Texas intrastate natural gas pipeline group. Our Natural Gas Pipelines business segment reported earnings before depreciation, depletion and amortization of $122.0 million on revenues of $2,108.8 million in the third quarter of 2005. This compares to earnings before depreciation, depletion and amortization of $105.2 million on revenues of $1,598.6 million in the third quarter of 2004. For the nine month period ended September 30, 2005, the segment reported earnings before depreciation, depletion and amortization expenses of $360.7 million on revenues of $5,198.3 million, and for the first nine months of 2004, earnings before depreciation, depletion and amortization expenses of $303.8 million on revenues of $4,591.3 million. The segment's overall $16.8 million (16%) increase in earnings before depreciation, depletion and amortization expenses in the third quarter of 2005 compared to the third quarter of 2004 included increases of $12.9 million (24%) from our Texas intrastate natural gas pipeline group, incremental earnings of $10.5 million from our TransColorado Pipeline, and an increase of $3.4 million (83%) from our 49% equity interest in the Red Cedar Gathering Company. The incremental earnings from TransColorado reflect our acquisition of the pipeline system from KMI effective November 1, 2004. The increase from Red Cedar was due to higher revenues from sales of excess fuel gas and natural gas gathering, and is included in the segment's earnings from equity investments, where we include our proportionate share of Red Cedar's net income pursuant to the equity method of accounting. The overall quarter-to-quarter increase in segment earnings before depreciation, depletion and amortization in the third quarter of 2005 compared to the third quarter of 2004 was partially offset by a $9.9 million (31%) decrease in earnings before depreciation, depletion and amortization expenses from our Kinder Morgan Interstate Gas Transmission system (KMIGT), mainly due to higher gas purchase costs and lower margins and volumes from operational sales of natural gas. KMIGT's operational gas sales are the result of both lower fuel recoveries pursuant to its transportation tariffs and recoveries of storage cushion gas volumes. 61 For the comparative nine month periods, the $56.9 million (19%) overall increase in segment earnings before depreciation, depletion and amortization expenses in 2005 over 2004 included increases of $28.5 million from the inclusion of TransColorado, $13.2 million (8%) from our Texas intrastate natural gas pipeline group, $11.4 million (108%) from Red Cedar, and $9.0 million (31%) from our Trailblazer Pipeline. Red Cedar's year-over-year increase in net income was largely driven by incremental sales of excess fuel gas, the result of favorable reductions in the amount of natural gas lost and used within the system during gathering operations. The increase from our Trailblazer natural gas pipeline system was mainly due to timing differences on the favorable settlements of pipeline transportation imbalances in the first quarter of 2005. For our Texas intrastate natural gas pipeline group, which includes our Kinder Morgan Tejas, Kinder Morgan Texas, Mier-Monterrey Mexico and Kinder Morgan North Texas pipelines, the increase in earnings before depreciation, depletion and amortization expenses for both comparative periods was primarily due to higher gross margins (revenues less cost of sales). Although total natural gas sales volumes decreased 8% in both the three and nine month periods of 2005 compared to 2004, largely due to lower electric generation demand and to reduced sales to lower margin customers, the group earned higher margins in our recurring sales business and incremental storage and service revenues. The intrastate group operated throughout Hurricane Rita and experienced only minor damage and some temporary service interruptions. The segment's overall increase in earnings before depreciation, depletion and amortization in the first nine months of 2005 compared to the first nine months of 2004 was partially offset by a $4.5 million (37%) decrease in earnings from our Casper Douglas natural gas gathering system and a $1.2 million (2%) decrease in earnings from KMIGT. The decrease from Casper Douglas was primarily due to lower natural gas sales volumes caused by both normal field declines and higher fuel reimbursement charges that reduced volumes available for sale. The year-over-year decrease in earnings from KMIGT was due to the third quarter 2005 decrease described above; partially offset by an $8.7 million increase in earnings before depreciation, depletion and amortization in the first half of 2005 versus the first half of 2004 due to higher operational sales of natural gas and favorable imbalance valuation adjustments. Total segment revenues, including revenues from natural gas sales, increased $510.2 million (32%) and $607.0 million (13%), respectively, in the third quarter and first nine months of 2005, compared to the same year-earlier periods. Combined operating expenses, including natural gas purchase costs, increased $498.7 million (33%) and $561.7 million (13%), respectively, in the third quarter and first nine months of 2005, when compared to the same periods last year. The increases in revenues and operating expenses in both comparative periods were largely due to higher natural gas sales revenues and higher natural gas cost of sales, due mainly to higher commodity prices and the sales activities of our Texas intrastate natural gas pipeline group. For the intrastate group combined, revenues from the sales of natural gas increased $500.2 million (34%) in the third quarter of 2005 and $570.3 million (14%) in the first nine months of 2005, when compared to the same periods of 2004. Similarly, costs of sales, including natural gas purchase costs, increased $490.8 million (34%) in the third quarter of 2005 and $563.9 million (14%) in the first nine months of 2005, versus the same periods in 2004. The inclusion of the TransColorado Pipeline in our 2005 results accounted for total revenue increases of $12.0 million and $32.5 million, respectively, and incremental operating expenses of $1.5 million and $4.1 million, respectively, in the third quarter and first nine months of 2005. Our Texas intrastate group both purchases and sells significant volumes of natural gas, which is often stored and/or transported on its pipelines. Our objective is to match every purchase and sale, thus locking-in an acceptable margin that is the equivalent of a transportation fee. In addition, we make use of energy financial instruments, such as over-the-counter forward contracts and both fixed price and basis swaps to help lock-in favorable margins from our natural gas purchase and sales activities, thereby generating more stable earnings during periods of fluctuating natural gas prices. The purchase and sale activities from our Texas intrastate pipeline group result in considerably higher revenues and operating expenses compared to the interstate operations of our Rocky Mountain pipelines, which include our KMIGT, Trailblazer and TransColorado pipelines. However, due to the fact that we sell natural gas in the same 62 price environment in which it is purchased, the increases in our gas purchase costs are largely offset by corresponding increases in our sales revenues. We realize earnings by capturing the favorable differences between the changes in our gas sales prices, on the one hand, and the changes in our gas purchase prices and transportation costs, on the other hand. That is why we believe, with regard to our results of operations analysis, that earnings before depreciation, depletion and amortization is a better comparative performance indicator than revenues and costs of sales because the mix of natural gas volumes between sales and transportation service often affects revenues but not margin. Earnings from equity investments increased $3.4 million (65%) and $11.2 million (77%), respectively, in the third quarter and first nine months of 2005, when compared to the same periods last year. The increases were chiefly due to higher net income earned by Red Cedar during 2005, as described above. The segment's interest income and earnings from other income items increased $1.5 million and $0.9 million, respectively, in the third quarter and first nine months of 2005, compared to the same periods last year. The increases were mainly due to incremental gains from property disposals recognized in the third quarter of 2005 by Kinder Morgan Tejas. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, increased $2.0 million (15%) and $6.8 million (17%), respectively, in the third quarter and first nine months of 2005, when compared to the same periods last year. The increases were largely due to the inclusion of depreciation expense on the acquired TransColorado Pipeline and to higher depreciation expenses on the assets of our Texas intrastate natural gas pipeline group, due to additional capital investments made since the end of the third quarter of 2004. CO2
Three Months Ended Nine Months Ended September 30, September 30, -------------------- ------------------- 2005 2004 2005 2004 ---- ---- ---- ---- (In thousands, except operating statistics) Revenues................................................... $ 163,079 $ 121,777 $ 488,271 $ 337,935 Operating expenses(a)...................................... (48,546) (43,331) (152,389) (123,620) Earnings from equity investments........................... 5,533 7,711 21,932 25,552 Other, net-income (expense)................................ (6) 10 (6) 42 Income taxes............................................... (151) (49) (263) (96) ----------- ----------- ------------ ------------ Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments............................................ 119,909 86,118 357,545 239,813 Depreciation, depletion and amortization expense(b)........ (34,658) (30,465) (111,822) (86,583) Amortization of excess cost of equity investments.......... (505) (505) (1,513) (1,513) ----------- ----------- ------------ ------------ Segment earnings......................................... $ 84,746 $ 55,148 $ 244,210 $ 151,717 =========== =========== ============ ============ Carbon dioxide volumes transported (Bcf)(c)................ 153.6 149.4 479.0 470.5 =========== =========== ============ ============ SACROC oil production (MBbl/d)(d).......................... 30.8 27.7 32.4 27.1 =========== =========== ============ ============ Yates oil production (MBbl/d)(d)........................... 24.1 20.2 24.0 18.8 =========== =========== ============ ============ Natural gas liquids sales volumes (MBbl/d)(e).............. 9.4 7.7 9.5 7.3 =========== =========== ============ ============ Realized weighted average oil price per Bbl(f)(g).......... $ 26.12 $ 25.21 $ 27.46 $ 25.28 =========== =========== ============ ============ Realized weighted average natural gas liquids price per $ 41.89 $ 33.05 $ 37.09 $ 29.25 =========== =========== ============ ============ Bbl(g)(h).................................................. - ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes depreciation, depletion and amortization expense associated with oil and gas production activities and gas processing activities in the amount of $30,195 for the third quarter of 2005, $26,901 for the third quarter of 2004, $98,220 for the first nine months of 2005 and $75,501 for the first nine months of 2004. Includes depreciation, depletion and amortization expense associated with sales and transportation services activities in the amount of $4,463 for the third quarter of 2005, $3,564 for the third quarter of 2004, $13,602 for the first nine months of 2005 and $11,082 for the first nine months of 2004. (c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes. (d) Represents 100% of the production from the field. We own an approximate 97% working interest in the SACROC unit and an approximate 50% working interest in the Yates unit. (e) Net to Kinder Morgan. (f) Includes all Kinder Morgan crude oil production properties. (g) Hedge gains/losses for oil and natural gas liquids are included with crude oil. 63 (h) Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. The segment's primary businesses involve the production, transportation and marketing of carbon dioxide, commonly called CO2, and the production and marketing of crude oil and natural gas. Our CO2 business segment reported earnings before depreciation, depletion and amortization of $119.9 million on revenues of $163.1 million in the third quarter of 2005. These amounts compare to earnings before depreciation, depletion and amortization of $86.1 million on revenues of $121.8 million in the same quarter last year. For the nine month period ended September 30, 2005, the segment reported earnings before depreciation, depletion and amortization of $357.5 million on revenues of $488.3 million, and for the nine months ended September 30, 2004, the segment reported earnings before depreciation, depletion and amortization of $239.8 million on revenues of $337.9 million. Both the $33.8 million (39%) increase in earnings before depreciation, depletion and amortization in the third quarter of 2005 over the third quarter of 2004 and the $117.7 million (49%) increase in the first nine months of 2005 over the first nine months of 2004 were driven by higher earnings from the segment's oil and natural gas producing activities, improved performance from carbon dioxide sales, and incremental contributions from our August 31, 2004 acquisition of the Kinder Morgan Wink Pipeline, a 450-mile crude oil pipeline system originating in the Permian Basin of West Texas and providing throughput to a crude oil refinery located in El Paso, Texas. Our CO2 segment's oil and natural gas producing activities, which include its natural gas processing activities, reported increases of $20.6 million (38%) and $84.5 million (57%), respectively, in earnings before depreciation, depletion and amortization for the three and nine months ended September 30, 2005, when compared to the same periods a year ago. For both periods, the growth in earnings from our oil and natural gas related activities was attributable to increased crude oil and natural gas processing plant liquids production and higher period-to-period average sale prices. We also realized, in the third quarter of 2005, our first full quarter of benefits from the completion of a power plant we constructed at the SACROC oil field unit, located in Scurry County, Texas. Construction began in mid-2004, and the project was completed at a cost of approximately $76 million. The power plant is being operated by KMI and will provide the majority of SACROC's future electricity needs. Combined daily oil production from the two largest oil field units in which we hold ownership interests increased 15% and 23%, respectively, in the third quarter and first nine months of 2005, as compared to the same prior-year periods. The two oil field interests include our approximate 97% working interest in the SACROC unit and our approximate 50% working interest in the Yates oil field unit, located south of Midland, Texas. Similarly, natural gas plant liquids product sales volumes increased 22% and 30%, respectively, in the third quarter and first nine months of 2005, when compared with the same periods of 2004. The year-over-year increases in plant product sales volumes were primarily due to the capital expenditures we have made since the end of the third quarter of 2004, and reflect the overall continuing strong demand for domestic energy commodities. For the first nine months of 2005, capital expenditures for our CO2 business segment totaled $219.5 million. We also benefited from increases of 4% and 9%, respectively, in our realized weighted average price of oil per barrel in the third quarter and first nine months of 2005, versus the same time periods in 2004. Crude oil prices have followed an upward trend since the end of the third quarter of 2004. Because we are exposed to market risks related to the price volatility of crude oil, natural gas liquids and carbon dioxide (to the extent contracts are tied to crude oil prices), we mitigate our commodity price risk through a long-term hedging strategy that is intended to generate more stable realized prices. For more information on our hedging activities, see Note 10 to our consolidated financial statements, included elsewhere in this report. Our CO2 segment's carbon dioxide sales and transportation activities reported increases of $13.2 million (41%) and $33.2 million (36%), respectively, in earnings before depreciation, depletion and amortization for the three and nine months ended September 30, 2005, when compared to the same periods a year ago. The increases were driven by higher revenues from carbon dioxide sales, incremental earnings from our Kinder Morgan Wink Pipeline, and increases of 3% and 2%, respectively, in carbon dioxide transportation volumes for the three and nine month periods of 2005 versus 2004. 64 The year-over-year increases in revenues from sales of carbon dioxide were due to both higher volumes and higher average prices. The increases in sales volumes were driven by increased demand for carbon dioxide in the Permian Basin. We do not recognize profits on carbon dioxide sales to ourselves. The operations of the acquired Kinder Morgan Wink Pipeline accounted for incremental earnings before depreciation, depletion and amortization of $4.0 million, revenues of $4.9 million and operating expenses of $0.9 million, respectively, in the third quarter of 2005, and incremental earnings before depreciation, depletion and amortization of $13.7 million, revenues of $17.1 million and operating expenses of $3.4 million, respectively, in the first nine months of 2005, when compared to the same time periods of 2004. Revenues earned by our CO2 segment during the third quarter and first nine months of 2005 increased $41.3 million (34%) and $150.4 million (45%), respectively, over comparable periods in the prior year. Both increases were mainly due to higher crude oil, plant product and carbon dioxide sales revenues, and higher crude oil transportation revenues, all described above. The segment's combined operating expenses increased $5.2 million (12%) in the third quarter of 2005 and $28.8 million (23%) in the first nine months of 2005, versus the same periods of 2004. The increases were primarily the result of higher property and production taxes, due to the period-to-period increases in oil production volumes and to an increase in capitalized assets since the end of the third quarter of 2004. Other factors contributing to the increases in segment operating expenses included higher fuel and power costs, due to increased carbon dioxide compression and equipment utilization, and higher operating and maintenance expenses, due to additional labor and field expenses related to higher production volumes. Earnings from equity investments, representing the equity earnings from our 50% ownership interest in the Cortez Pipeline Company, decreased $2.2 million (28%) in the third quarter of 2005 and $3.6 million (14%) in the first nine months of 2005, versus the same periods of 2004. The decreases were due to lower overall net income earned by Cortez, as a result of lower carbon dioxide transportation revenues due to lower average tariff rates. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, increased $4.2 million (14%) and $25.2 million (29%), respectively, in the third quarter and first nine months of 2005, when compared to the same periods last year. The increases were due to higher depreciable costs, related to incremental capital spending since September 2004, and higher depletion charges, related to higher period-to-period crude oil production. Terminals
Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 2005 2004 2005 2004 ---- ---- ---- ---- (In thousands, except operating statistics) Revenues................................................... $ 177,484 $ 133,461 $ 515,115 $ 389,682 Operating expenses(a)...................................... (94,318) (63,943) (271,470) (188,336) Earnings from equity investments........................... 18 (4) 51 3 Other, net-income (expense)................................ 886 (61) (293) (306) Income taxes............................................... (2,372) (2,285) (9,874) (5,003) ------------ ------------ ------------ ------------ Earnings before depreciation, depletion and amortization Expense and amortization of excess cost of equity 81,698 67,168 233,529 196,040 investments................................................ Depreciation, depletion and amortization expense........... (15,644) (10,607) (41,972) (31,330) Amortization of excess cost of equity investments.......... - - - - ----------- ----------- ----------- ----------- Segment earnings......................................... $ 66,054 $ 56,561 $ 191,557 $ 164,710 =========== =========== ============ ============ Bulk transload tonnage (MMtons)(b)......................... 20.5 21.8 63.3 61.6 =========== =========== =========== =========== Liquids leaseable capacity (MMBbl)......................... 40.3 36.5 40.3 36.5 =========== =========== =========== =========== Liquids utilization %...................................... 96.5% 95.8% 96.5% 95.8% =========== =========== =========== ===========
- ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Volumes for acquired terminals are included for all periods. 65 Our Terminals segment, which includes the operations of our dry-bulk material terminals and our petroleum and petrochemical-related liquids terminal facilities, reported earnings before depreciation, depletion and amortization of $81.7 million on revenues of $177.5 million in the third quarter of 2005. This compares to earnings before depreciation, depletion and amortization of $67.2 million on revenues of $133.5 million in the third quarter last year. For the first nine months of 2005, our Terminals segment reported earnings before depreciation, depletion and amortization of $233.5 million on revenues of $515.1 million, while in the same period of 2004, the segment reported earnings before depreciation, depletion and amortization of $196.0 million on revenues of $389.7 million. Since the end of the third quarter of 2004, we have invested approximately $273.7 million in cash and $49.6 million in common units to acquire assets and business operations included as part of our Terminals segment. Our terminal acquisitions since the end of the third quarter of 2004 primarily included the following: - the river terminals and rail transloading facilities operated by Kinder Morgan River Terminals LLC and its consolidated subsidiaries, acquired effective October 6, 2004; - our Kinder Morgan Fairless Hills terminal located along the Delaware River in Bucks County, Pennsylvania, acquired effective December 1, 2004; - our Texas Petcoke terminals, located in and around the Ports of Houston and Beaumont, Texas, acquired effective April 29, 2005; - three terminals acquired separately in July 2005: the Kinder Morgan Staten Island terminal, a dry-bulk terminal located in Hawesville, Kentucky and a liquids/dry-bulk facility located in Blytheville, Arkansas; - all of the ownership interests in General Stevedores, L.P., which operates a break-bulk terminal facility located along the Houston Ship Channel, acquired July 31, 2005; - our Kinder Morgan Blackhawk terminal located in Black Hawk County, Iowa, acquired in August 2005; and - a terminal-related repair shop located in Jefferson County, Texas, acquired in September 2005. Terminal operations acquired since the end of the third quarter of 2004 accounted for incremental amounts of earnings before depreciation, depletion and amortization of $15.7 million, revenues of $37.9 million and operating expenses of $21.4 million, respectively, in the third quarter of 2005, and incremental amounts of earnings before depreciation, depletion and amortization of $33.1 million, revenues of $88.6 million and operating expenses of $52.1 million, respectively, in the first nine months of 2005, when compared to the same periods a year ago. For all other terminal operations (those owned during both nine month periods), earnings before depreciation, depletion and amortization decreased $1.2 million (2%) in the third quarter of 2005 versus the third quarter of 2004, and increased $4.4 million (2%) in the first nine months of 2005 versus the first nine months of 2004. The 2005 decrease in third quarter earnings before depreciation, depletion and amortization from terminals owned during both years was primarily due to the effects of two Gulf Coast hurricanes in the third quarter of 2005, as described above in our discussion under "--Third Quarter 2005 Hurricanes." Specifically, our International Marine Terminals facility, a Louisiana partnership owned 66 2/3% by us, suffered property damage and a general loss of business due to the effects of Hurricane Katrina. Earnings before depreciation, depletion and amortization from our IMT facility decreased $4.1 million, revenues decreased $3.1 million and operating expenses increased $0.9 million in the third quarter of 2005 versus the third quarter of 2004. IMT is a multi-purpose bulk commodity transfer terminal facility located in Port Sulphur, Louisiana. It utilizes both land and a dock facility to generate revenues from annual throughput contracts under which the partnership agrees to transfer certain minimum quantities of bulk commodities. For the comparative nine months, IMT's earnings before depreciation, depletion and amortization decreased $5.6 million, revenues decreased $2.5 million and operating expenses increased $3.1 million. The year-over-year decrease in earnings reflects the impact of Hurricane Katrina in the third quarter of 66 2005, as well as higher labor, equipment rental and fuel expenses in the first half of 2005 versus the first half of 2004. In addition, due to the impact of the two third quarter hurricanes and their effect on Gulf Coast crude oil refineries, most of the terminal operations in our Texas Petcoke region temporarily ceased operations, our two large Gulf Coast liquids terminal facilities located on the Houston Ship Channel in Pasadena and Galena Park, Texas, were out of service for four days, and four separate facilities in Louisiana and Mississippi were shutdown for various lengths of time due to property damage from the storms. In total, our Terminals segment recognized $2.6 million in expense in the third quarter of 2005 to meet its insurance deductible for Hurricane Katrina and another $0.8 million to repair damaged facilities following Hurricane Rita. For the comparative quarterly period, total bulk tonnage volume was down 6% in the third quarter of 2005 when compared to the third quarter of 2004, primarily due to the hurricanes. Despite the temporary shutdowns, earnings before depreciation, depletion and amortization from our two large Gulf Coast liquids terminal facilities increased $4.3 million (27%) and $9.2 million (20%), respectively, in the third quarter and first nine months of 2005, when compared to the same periods last year. The two terminals serve as a distribution hub for Houston's crude oil refineries, and the period-to-period increases in the terminals' earnings before depreciation, depletion and amortization expenses were primarily driven by higher revenues at our Pasadena terminal, due to higher sales of petroleum transmix, new customer agreements and certain contract price escalations. Despite a decrease in total liquids transfer volumes in the third quarter of 2005, due in large part to the short-term shutdowns related to Hurricane Rita, for the two terminals combined, total throughput volumes increased 2% in the first nine months of 2005 versus the same year-earlier period. For our entire liquids terminals combined, total throughput volumes increased 1% in both the third quarter and first nine months of 2005, versus the same periods in 2004. The increases were due to higher distillate, vegetable oil, and oil field liquids volumes. Through a combination of business acquisitions and internal capital spending, we have increased our liquids leaseable capacity by 3.8 million barrels (10%) since the end of the third quarter of 2004, while at the same time, increasing our liquids utilization rate (the ratio of our actual output to our estimated potential output) by 1%. Other contributions to the growth in earnings before depreciation, depletion and amortization for the comparative three and nine month periods from terminals owned during both years include increases of $1.6 million (37%) and $1.2 million (8%), respectively, from our Southeast region, and increases of $0.7 million (6%) and $2.7 million (8%), respectively, from our Midwest region. For our Southeast region, the increases were largely due to improved performance at our terminal operations located in and around the Tampa, Florida area. These operations include the import and export business of our Kinder Morgan Tampaplex terminal, the commodity transfer operations of our Port Sutton terminal, and the terminal stevedoring services we perform along Tampa Bay. For our Midwest terminal region, the increases included higher earnings from our Dakota bulk terminal, located along the Mississippi River near St. Paul, Minnesota, and from our Milwaukee, Wisconsin bulk commodity terminal. The period-to-period increases in earnings from Dakota were primarily due to higher revenues generated by a cement unloading and storage facility, which was designed and built by our River Consulting engineering operations and which began operations in late 2004. The increases from our Milwaukee bulk terminal were mainly due to an increase in coal handling revenues related to higher coal truckage within the State of Wisconsin. Segment revenues for all terminals owned during both nine month periods increased $6.1 million (5%) and $36.8 million (9%), respectively, in the third quarter and first nine months of 2005, when compared to the same prior-year periods. The quarter-to-quarter increase was primarily due to a $5.1 million (23%) increase in revenues from our Pasadena and Galena Park Gulf Coast liquids terminals, as described above. The year-over-year increase of $36.8 million was mainly due to the following: - an $11.6 million (18%) increase from our Pasadena and Galena Park Gulf Coast facilities, due primarily to higher petroleum transmix sales and additional customer contracts; - an $8.5 million (13%) increase from our Midwest region, due primarily to higher cement handling revenues at our Dakota terminal, increased tonnage at our Milwaukee terminal, and higher oil sales at our Dravosburg, Pennsylvania terminal; 67 - an $8.5 million (20%) increase from our Mid-Atlantic region, due primarily to higher coal volumes and higher dockage revenues at our Shipyard River terminal, located in Charleston, South Carolina, and to higher synfuel, cement handling and dockage revenues at our Pier IX bulk terminal, located in Newport News, Virginia; and - a $3.5 million (10%) increase from our Southeast region, due primarily to increased tonnage, storage and stevedoring services performed at terminal sites located in Tampa Bay and Port Sutton, Florida. Operating expenses for all terminals owned during both nine month periods increased $9.0 million (14%) and $31.0 million (16%), respectively, in the third quarter and first nine months of 2005, when compared to the same periods a year earlier. The overall quarter-to-quarter increase in segment operating expenses includes increases of $3.3 million (30%) from our Midwest terminals, $1.6 million (11%) from our Lower Mississippi River (Louisiana) terminals, and $0.8 million (14%) from our Gulf Coast terminals. For the comparative nine month periods, the overall increase in operating expenses includes increases of $9.3 million (50%) from our Mid-Atlantic terminals, $6.6 million (20%) from our Midwest terminals, and $5.1 million (12%) from our Louisiana terminals. The increases in expenses for the terminals included in our Louisiana region were largely due to additional insurance and property damage expenses related to the two Gulf Coast hurricanes in the third quarter of 2005. The increases in operating expenses from our Midwest terminals included higher expenses at our Milwaukee terminal, due to increased wharfage, trucking and maintenance expenses associated with the increase in coal volumes; higher expenses at our Dakota terminal, due to repairs and higher labor expenses associated with the higher cement volumes; and higher cost of sales expense at our Dravosburg terminal, due to oil purchasing costs and inventory maintenance. The increases at our Gulf Coast terminals were mainly due to higher period-to-period labor expenses, dock expenses and dredging work. The Mid-Atlantic increases were largely due to higher operating, maintenance and labor expenses at our Shipyard River and Pier IX terminals, due to higher bulk tonnage volumes, and to higher labor and equipment maintenance expenses at our Chesapeake Bay, Maryland bulk terminal, due to higher movements of petroleum coke. The segment's other income items increased $0.9 million in the third quarter of 2005 versus the third quarter of 2004, but were flat across both nine month periods. The increase in the comparative quarterly period was due to a gain on sale of terminal property located at our liquids terminal facility in Argo, Illinois. The segment's income tax expenses were essentially flat across both third quarter periods, but increased $4.9 million (97%) in the first nine months of 2005, compared to the first nine months of 2004. The increase was mainly due to an incremental $3.5 million of income tax expense related to the taxable income of Kinder Morgan River Terminals LLC and its consolidated subsidiaries, which we acquired effective October 6, 2004. The remaining $1.4 million increase was attributable to higher taxable income from Kinder Morgan Bulk Terminals, Inc. and its consolidated subsidiaries. Compared to the same periods in 2004, non-cash depreciation, depletion and amortization charges increased $5.0 million (47%) in the third quarter of 2005 and $10.6 million (34%) in the first nine months of 2005. In addition to increases associated with normal capital spending, the overall increases reflect higher depreciation charges due to the terminal acquisitions we have made since the third quarter of 2004. Collectively, the terminal assets that we have acquired since the end of the third quarter of 2004 accounted for incremental depreciation expenses of $4.4 million and $8.8 million in the three and nine month periods ended September 30, 2005, respectively. 68 Other
Three Months Ended Nine Months Ended September 30, September 30, ------------------- ------------------- 2005 2004 2005 2004 ---- ---- ---- ---- (In thousands-income/(expense)) General and administrative expenses........................ $ (47,073) $ (37,816) $ (171,058) $ (125,527) Unallocable interest, net.................................. (69,688) (47,295) (196,362) (141,108) Minority interest.......................................... (1,806) (2,789) (6,648) (7,332) Loss from early extinguishment of debt..................... - - - (1,424) ----------- ----------- ----------- ------------ Interest and corporate administrative expenses........... $ (118,567) $ (87,900) $ (374,068) $ (275,391) ============= ============ ============ ============
Items not attributable to any segment include general and administrative expenses, unallocable interest income, interest expense and minority interest. We also included the $1.4 million loss from our early extinguishment of debt in May 2004 as an item not attributable to any business segment. The loss represented the excess of the price we paid to repurchase and retire the principal amount of $84.3 million of tax-exempt industrial revenue bonds over the bonds' carrying value and unamortized debt issuance costs. Pursuant to certain provisions that gave us the right to call and retire the bonds prior to maturity, we took advantage of the opportunity to refinance at lower rates, and we included the $1.4 million loss under the caption "Other, net" in our accompanying consolidated statements of income. Our general and administrative expenses, which include such items as salaries and employee-related expenses, payroll taxes, legal fees, unallocated litigation and environmental accruals, insurance, and office supplies and rentals, increased $9.3 million (24%) and $45.5 million (36%), respectively, in the third quarter and first nine months of 2005 compared to the same periods in 2004. The increase in the third quarter of 2005 versus the third quarter of 2004 was primarily due to higher period-to-period employee costs, associated with acquisitions; higher expenses incurred from KMI's operation and maintenance of our natural gas pipeline assets, associated with higher actual costs in 2005 versus lower negotiated settlement costs in 2004; and higher legal, corporate secretary and other shared services. For the comparative nine month periods, higher general and administrative expenses in 2005 versus 2004 were largely due to incremental litigation and environmental settlement expenses of $33.4 million. The additional charges recognized in 2005 consisted of a $25 million expense for a settlement reached in the first quarter between us and a shipper on our Kinder Morgan Tejas natural gas pipeline system, and a cumulative $8.4 million expense related to settlements of environmental matters at certain of our operating sites located in the State of California. The remaining increase in year-over-year general and administrative expenses reflects the same items discussed above for the comparative third quarter periods. For more information on our litigation matters, see Note 3 to our consolidated financial statements, included elsewhere in this report. Unallocable interest expense, net of interest income, increased $22.4 million (47%) and $55.3 million (39%), respectively, in the third quarter and first nine months of 2005, compared to the same year-earlier periods. The increases were due to both higher average debt levels and higher effective interest rates. The period-to-period increases in average borrowings were largely due to a net increase of $800 million in principal amount of long-term senior notes since September 30, 2004. We closed public offerings of $500 million in principal amount of senior notes in both November 2004 and March 2005, and we retired a principal amount of $200 million in March 2005. We issued our senior notes pursuant to our available shelf registration statements, principally to refinance commercial paper borrowings used for both internal capital spending and acquisition expenditures made since the end of the third quarter of 2004. The period-to-period increases in our average borrowing rates reflect a general rise in interest rates since the end of the third quarter of 2004. The weighted average interest rate on all of our borrowings increased 10% in both the third quarter and first nine months of 2005 compared to the same periods last year. We use interest rate swap agreements to help manage our interest rate risk. The swaps are contractual agreements we enter into in order to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. However, in a period of rising interest rates, these swaps will result in period-to-period increases in our interest expense. For more information on our interest rate swaps, see Note 10 to our consolidated financial statements, included elsewhere in this report. 69 Minority interest, representing the deduction in our consolidated net income attributable to all outstanding ownership interests in our five operating limited partnerships and their consolidated subsidiaries that are not held by us, decreased $1.0 million (35%) and $0.7 million (9%), respectively, in the third quarter and first nine months of 2005, compared to the same periods a year ago. The decreases were primarily due to lower third quarter income allocated to the 33 1/3% minority interest in the IMT Partnership in 2005, due to business interruption caused by Hurricane Katrina. Financial Condition Capital Structure We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 60% equity and 40% debt. The following table illustrates the sources of our invested capital (dollars in thousands). In addition to our results of operations, these balances are affected by our financing activities as discussed below:
September 30, December 31, ------------ ------------ 2005 2004 ------------ ------------ Long-term debt, excluding market value of interest rate swaps.. $5,187,273 $4,722,410 Minority interest.............................................. 40,597 45,646 Partners' capital, excluding accumulated other comprehensive 4,691,963 4,353,863 ------------ ------------ loss........................................................... Total capitalization......................................... 9,919,833 9,121,919 Short-term debt, less cash and cash equivalents................ - - ------------ ------------ Total invested capital....................................... $ 9,919,833 $ 9,121,919 ============ ============ Capitalization: Long-term debt, excluding market value of interest rate swaps 52.3% 51.8% Minority interest............................................ 0.4% 0.5% Partners' capital, excluding accumulated other comprehensive 47.3% 47.7% ------------ ------------ loss........................................................... 100.0% 100.0% ============ ============ Invested Capital: Total debt, less cash and cash equivalents and excluding market value of interest rate swaps..................... 52.3% 51.8% Partners' capital and minority interest, excluding accumulated other comprehensive loss ............................... 47.7% 48.2% ------------ ------------ 100.0% 100.0% ============ ============
Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through borrowings under our credit facility, issuing short-term commercial paper, long-term notes or additional common units or issuing additional i-units to KMR. In general, we expect to fund: - cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; - expansion capital expenditures and working capital deficits with retained cash (resulting from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings, the issuance of additional common units or the issuance of additional i-units to KMR; - interest payments with cash flows from operating activities; and - debt principal payments with additional borrowings, as such debt principal payments become due, or by the issuance of additional common units or the issuance of additional i-units to KMR. 70 As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. We are able to access this segment of the capital market through KMR's purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors. Short-term Liquidity Our principal sources of short-term liquidity are our $1.6 billion revolving bank credit facility, our $1.6 billion short-term commercial paper program (which is supported by our revolving bank credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings) and cash provided by operations. In August 2005, we replaced our previous five-year credit facility with a five-year senior unsecured revolving credit facility that has a borrowing capacity of $1.6 billion, and we increased our commercial paper program by $350 million to provide for the issuance of up to $1.6 billion. Our current five-year credit facility is due August 18, 2010, and can be used for general corporate purposes and as a backup for our commercial paper program. There were no borrowings under our credit facility as of September 30, 2005. After inclusion of our outstanding commercial paper borrowings and letters of credit, the remaining available borrowing capacity under our credit facility was $394.2 million as of September 30, 2005. On August 1, 2005, KMI announced that it had entered into a definitive agreement to acquire all of the outstanding shares of Terasen Inc., a provider of energy and utility services based in Vancouver, British Columbia, Canada, for an aggregate consideration of approximately US$5.6 billion, consisting of cash, stock of KMI and the assumption of debt. For more information on this transaction, see Note 1 to our consolidated financial statements, included elsewhere in this report. On August 2, 2005, following KMI's announcement of the proposed acquisition, Standard & Poor's Rating Services placed our debt credit ratings, as well as KMI's ratings, on CreditWatch with negative implications. As of October 26, 2005, there was no change in our S&P credit rating. In addition, some of our customers are experiencing, or may experience in the future, severe financial problems that have had a significant impact on their creditworthiness. We are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Operating Activities Net cash provided by operating activities was $901.6 million for the nine months ended September 30, 2005, versus $837.9 million in the comparable period of 2004. The period-to-period increase of $63.7 million (8%) in cash flow from operations consisted of: - a $140.6 million increase in cash from overall higher partnership income, net of non-cash items including depreciation charges and undistributed earnings from equity investments; - a $2.1 million increase related to higher distributions received from equity investments; - a $53.0 million decrease in cash inflows relative to net changes in working capital items; and - a $26.0 million decrease in cash inflows relative to net changes in non-current assets and liabilities. The higher partnership income reflects the increase in cash earnings across all four of our reportable business segments in the first nine months of 2005, as discussed above in "-Results of Operations." The increase in cash inflows from our equity investees was primarily due to higher distributions received from Plantation Pipe Line and Red Cedar in the first nine months of 2005, reflecting higher year-over-year earnings for both investees. The overall 71 increase in distributions was partially offset by lower distributions from Cortez Pipeline, due to lower overall partnership net income in 2005 versus 2004. The decrease in operating cash flows from working capital items was mainly due to net changes in accounts payables and receivables; in 2005, timing differences resulted in higher receivables, which more than offset an increase in payables relative to the first nine months of 2004. The decrease in cash inflows relative to net changes in non-current assets and liabilities related to, among other things, higher payments made in the first nine months of 2005 to reduce long-term liabilities and reserves for items such as: natural gas imbalances, reserves for natural gas and natural gas liquids storage, and pipeline rate case liabilities. Investing Activities Net cash used in investing activities was $905.6 million for the nine month period ended September 30, 2005, compared to $713.2 million in the comparable 2004 period. The $192.4 million (27%) increase in cash used in investing activities was primarily attributable to: - a $147.2 million increase due to higher expenditures made for strategic business acquisitions; - a $32 million increase in capital expenditures; and - a $20.4 million increase related to additional investments in underground natural gas storage volumes. For the nine months ended September 30, 2005, our acquisition outlays totaled $289.7 million, including cash outflows of $188.6 million for the acquisition of bulk terminal assets from Trans-Global Solutions, Inc., $50.9 million for our North Dayton, Texas natural gas storage facility, and $23.9 million for our acquisition of the Kinder Morgan Staten Island terminal. For the nine months ended September 30, 2004, our acquisition outlays totaled $142.5 million, including cash outflows of $90.8 million for the acquisition of Kinder Morgan Wink Pipeline, L.P., formerly Kaston Pipeline Company, L.P., and $48.1 million for the acquisition of seven refined petroleum products terminals from Exxon Mobil Corporation. Including expansion and maintenance projects, our capital expenditures were $597.2 million in the first nine months of 2005, compared to $565.2 million in the same prior-year period. We continue to expand and grow our existing asset infrastructure and have current projects in place that will further increase production and throughput across our business portfolio. Our sustaining capital expenditures were $95.8 million for the first nine months of 2005 compared to $82.9 million for the first nine months of 2004. As of September 30, 2005, our forecasted expenditures for the remaining three months of 2005 for sustaining capital expenditures were approximately $48.3 million, based on our 2005 sustaining capital expenditure forecast. This amount has been committed primarily for the purchase of plant and equipment. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. In the third and fourth quarters of 2005, we made the following announcements related to our investing activities: - On August 4, 2005, we announced plans for a second expansion to our Pacific operations' East Line Pipeline. In addition to our approximate $210 million East Line expansion initially proposed in October 2002, this second expansion consists of replacing approximately 140 miles of 12-inch diameter pipe between El Paso, Texas and Tucson, Arizona with 16-inch diameter pipe. The project also includes the construction of two additional pump stations on the East Line. The project is expected to cost approximately $130 million. We began the permitting process for this project in September 2005, we expect construction to begin in January 2007, and we expect to complete the expansion project in the summer of 2007; - On August 15, 2005, we announced plans to expand our Texas intrastate natural gas pipeline system into the Permian Basin by converting an approximate 254-mile segment of a previously acquired 24-inch diameter Texas crude oil pipeline from carrying crude oil to natural gas. The project was completed at a cost of approximately $46 million and service was commenced in early October 2005. The expansion accesses a 72 number of natural gas processing plants in West Texas and provides transportation service from McCamey, Texas to just west of Austin, Texas. The expansion complements our 2004 conversion of a 135-mile segment of the same pipeline between Katy and Austin, Texas, that began natural gas service in July 2004. Approximately 95% of the 150 million cubic feet per day of new natural gas capacity being created by this conversion project is already supported by customer contracts and the project is being phased in through the first quarter of 2006; - On August 17, 2005, we announced that we had entered into a Memorandum of Understanding with Sempra Pipelines & Storage, a unit of Sempra Energy, to pursue development of a proposed new natural gas pipeline that would link producing areas in the Rocky Mountain region to the upper Midwest and Eastern United States. The proposed 1,500-mile, 42-inch diameter Rockies Express Pipeline would have a capacity of up to two billion cubic feet per day of natural gas and would cost an estimated $3 billion to complete. The pipeline will originate at the Cheyenne Market Hub in northeastern Colorado and extend to eastern Ohio with an ultimate route to be selected based on shipper interest. Under the memorandum of understanding with Sempra, we will share responsibility for development activities with Sempra, but initially, we would own 66 2/3% of the equity in the proposed pipeline and Sempra would own the remaining 33 1/3% interest. Pending customer commitments and regulatory approval, the proposed pipeline is projected to be staged into service beginning in late 2007, and the eastern portion of the project, providing direct access to markets in the Northeast United States, is anticipated to be in service in late 2008 or early 2009. - On September 22, 2005, we announced the start of a binding open season for our proposed Kinder Morgan Louisiana Pipeline. The pipeline would provide take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas (LNG) plant now under construction in Cameron Parish, Louisiana. We plan to invest approximately $490 million to build this new interstate natural gas pipeline that will originate at the Sabine Pass LNG terminal and extend into Evangeline Parish, Louisiana. The Kinder Morgan Louisiana Pipeline will consist of two segments: (i) a 137-mile large diameter pipeline with firm capacity of about 2.1 million dekatherms per day of natural gas that will connect to various interstate and intrastate pipelines within Louisiana, and (ii) a 1-mile pipeline with firm capacity of about 1.3 million dekatherms per day that will connect to KMI's Natural Gas Pipeline Company of America's natural gas pipeline. Prior to the open season, we had already obtained prearranged conditional agreements from multiple shippers for the combined 3.4 million dekatherms per day of initial project capacity. Pending various shipper and regulatory approvals, the pipeline could be in service as early as the first quarter of 2009; and - On October 5, 2005, and on October 18, 2005, we and Sempra announced that we had entered into separate memoranda of understandings with the Wyoming Natural Gas Pipeline Authority and with subsidiaries of EnCana Corporation, respectively, with regard to our proposed development of the Rockies Express Pipeline, announced on August 17, 2005 (discussed above). The WNGPA is an instrumentality of the State of Wyoming that was formed by the state legislature in order to facilitate production and transportation of Wyoming natural gas. Pursuant to the memorandum of understanding with the WNGPA, the WNGPA will contract for up to 200 million cubic feet per day of firm capacity natural gas on the proposed pipeline, explore the use of its $1 billion in bonding authority to provide debt financing for the project, and provide support for the extension of the project to the Opal Hub in southwestern Wyoming. Pursuant to the memorandum of understanding with EnCana, EnCana Gas Marketing has agreed to negotiate with the project for firm transportation capacity during an upcoming open season. Combined with previous agreements with the WNGPA and a Sempra affiliate, we now have conditional commitments that account for approximately 50% of the pipeline's two billion cubic feet per day capacity. Also, under the terms of the EnCana memorandum of understanding and subject to final negotiations, it is contemplated that EnCana will sell its Entrega Gas Pipeline to the Rockies Express project. EnCana recently began constructing the Entrega Pipeline, a 330-mile, 36 to 42-inch diameter interstate natural gas pipeline that will link growing Rocky Mountain gas production areas to the Cheyenne Hub. Under a previous agreement, we had contracted with EnCana to operate the Entrega system, and we will now also market the available capacity on the system. Financing Activities Net cash provided by financing activities amounted to $4.2 million for the nine months ended September 30, 2005. For the same nine months of 2004, we used $141.6 million in financing activities. The $145.8 million overall 73 increase in cash inflows provided by financing activities was primarily due to: - a $218 million increase from overall debt financing activities; - a $32.4 million increase from overall equity issuances; and - a $115.1 million decrease from higher partnership distributions. Our changes in cash from debt financing activities include both issuances and payments of debt, and debt issuance costs. The period-to-period increase in cash inflows from our overall debt financing activities was primarily due to the following: - a $498.7 million increase from the issuance of senior notes. On March 15, 2005, we closed a public offering of $500 million in principal amount of 5.80% senior notes due March 15, 2035. We used the proceeds from this issuance to reduce the borrowings under our commercial paper program; - a $97.2 million increase from our July 2004 loan to Plantation Pipe Line Company, which corresponded to our 51.17% ownership interest, to allow Plantation to pay all of its outstanding credit facility and commercial paper borrowings. In exchange, we received a seven year note receivable bearing interest at the rate of 4.72% per annum; - an $84.3 million increase from the May 2004 redemption and retirement of the principal amount of four series of tax-exempt bonds related to certain liquids terminal facilities. Pursuant to certain provisions that gave us the right to call and retire the bonds prior to maturity, we took advantage of the opportunity to refinance at lower rates; - a $200 million decrease from the retirement of senior notes. On March 15, 2005, we paid a maturing amount of $200 million in principal amount of 8.0% senior notes due on that date; and - a $264.8 million decrease due to lower net commercial paper borrowings in the first nine months of 2005 versus the first nine months of 2004. The $32.4 million increase in cash inflows from partnership equity issuances was primarily related to the incremental cash we received for our third quarter 2005 issuance of common units compared to our first quarter 2004 issuances of common and i-units. In the third quarter of 2005, we issued, in a public offering, 5,750,000 of our common units at a price of $51.25 per unit. After commissions and underwriting expenses, we received net proceeds of $283.6 million for the issuance of these units. Similarly, in a February 2004 public offering, we issued an additional 5,300,000 of our common units at a price of $46.80 per unit, less commissions and underwriting expenses, and in March 2004, we issued an additional 360,664 of our i-units to KMR at a price of $41.59 per share, less closing fees and commissions. After all fees, we received net proceeds of $252.7 million for the issuance of these common and i-units. We used the proceeds from each of these three issuances to reduce the borrowings under our commercial paper program. Distributions to all partners, consisting of our common and Class B unitholders, our general partner and minority interests, totaled $696.5 million in the first nine months of 2005 compared to $581.4 million in the same year-earlier period. The increase in distributions was due to an increase in the per unit cash distributions paid, an increase in the number of units outstanding and an increase in our general partner incentive distributions. The increase in our general partner incentive distributions resulted from both increased cash distributions per unit and an increase in the number of common units and i-units outstanding. Partnership Distributions Our partnership agreement requires that we distribute 100% of "Available Cash," as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available Cash consists generally of all of our cash receipts, including cash received by our operating partnerships and net reductions in reserves, less cash disbursements and net additions to 74 reserves and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% interest in SFPP. Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units. We do not distribute cash to i-unit owners but retain the cash for use in our business. However, the cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to our general partner. Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Available cash for each quarter is distributed: - first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter; - second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter; - third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and - fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, and 50% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. Our general partner's incentive distribution for the distribution that we declared for the third quarter of 2005 was $121.5 million. Our general partner's incentive distribution for the distribution that we declared for the third quarter of 2004 was $99.1 million. Our general partner's incentive distribution that we paid during the third quarter of 2005 to our general partner (for the second quarter of 2005) was $115.7 million. Our general partner's incentive distribution that we paid during the third quarter of 2004 to our general partner (for the second quarter of 2004) was $94.9 million. We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions; however, no assurance can be given that future distributions will continue at such levels. Litigation and Environmental As of September 30, 2005, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $26.7 million. The reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired. Please refer to Note 3 to our consolidated financial statements included elsewhere in this report for additional information on our pending environmental and litigation matters. We believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing 75 circumstances could cause these matters to have a material adverse impact. Pursuant to our continuing commitment to operational excellence and our focus on safe, reliable operations, we have implemented, and intend to implement in the future, enhancements to certain of our operational practices in order to strengthen our environmental and asset integrity performance. The repairs resulting from these enhancements have resulted and we expect that they will result in higher capital and/or operating costs and expenses; however, we believe these enhancements and repairs will provide us the greater long term benefits of improved environmental and asset integrity performance. Certain Contractual Obligations There have been no material changes in either certain contractual obligations or our obligations with respect to other entities which are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2004 in our 2004 Form 10-K report. Information Regarding Forward-Looking Statements This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include: - price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, coal and other bulk materials and chemicals in the United States; - economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; - changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; - our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to make expansions to our facilities; - difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines; - our ability to successfully identify and close acquisitions and make cost-saving changes in operations; - shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us; - changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete; - changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities; - our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities; 76 - our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences; - interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes; - our ability to obtain insurance coverage without significant levels of self-retention of risk; - acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; - capital markets conditions; - the political and economic stability of the oil producing nations of the world; - national, international, regional and local economic, competitive and regulatory conditions and developments; - the ability to achieve cost savings and revenue growth; - inflation; - interest rates; - the pace of deregulation of retail natural gas and electricity; - foreign exchange fluctuations; - the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; - the extent of our success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities; - engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells; - the uncertainty inherent in estimating future oil and natural gas production or reserves; - the timing and success of business development efforts; and - unfavorable results of litigation and the fruition of contingencies referred to in Note 16 to our consolidated financial statements included elsewhere in this report. You should not put undue reliance on any forward-looking statements. See Items 1 and 2 "Business and Properties--Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2004, for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in our 2004 Form 10-K report. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments. 77 Item 3. Quantitative and Qualitative Disclosures About Market Risk. There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2004, in Item 7A of our 2004 Form 10-K report. For more information on our risk management activities, see Note 10 to our consolidated financial statements included elsewhere in this report. Item 4. Controls and Procedures. As of September 30, 2005, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 78 PART II. OTHER INFORMATION Item 1. Legal Proceedings. See Part I, Item 1, Note 3 to our consolidated financial statements entitled "Litigation, Environmental and Other Contingencies," which is incorporated herein by reference. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. Effective August 1, 2005, we issued 64,412 common units as part of the purchase price for all of the partnership interests in General Stevedores, L.P. The total purchase price for the acquired partnership interests was approximately $8.9 million, consisting of $2.1 million in cash, $3.4 million in common units, and $3.4 million in assumed liabilities, including debt of $3.0 million. The issuance of the units was exempt from registration under Section 4(2) of the Securities Act of 1933 because we issued the units to the two owners of General Stevedores, L.P. in a transaction not involving a public offering. Item 3. Defaults Upon Senior Securities. None. Item 4. Submission of Matters to a Vote of Security Holders. None. Item 5. Other Information. None. Item 6. Exhibits. 4.1 -- Certain instruments with respect to long-term debt of the Partnership and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of the Partnership and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. ss.229.601. 10.1 -- Credit Agreement, dated as of August 5, 2005, by and among Kinder Morgan Energy Partners, L.P.; Kinder Morgan Operating L.P. "B"; the lenders party thereto; Wachovia Bank, National Association, as Administrative Agent; Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents; The Royal Bank of Scotland plc and Barclays Bank PLC, as Co-Documentation Agents (filed as Exhibit 10.1 to Kinder Morgan Energy Patners, L.P.'s Current Report on Form 8-K, filed on August 11, 2005, and incorporated herein by reference). 11 -- Statement re: computation of per share earnings. 31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 79 32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 80 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware limited partnership) By: KINDER MORGAN G.P., INC., its sole General Partner By: KINDER MORGAN MANAGEMENT, LLC, the Delegate of Kinder Morgan G.P., Inc. /s/ Kimberly J. Allen ------------------------------ Kimberly J. Allen Vice President and Chief Financial Officer (principal financial officer and principal accounting officer) Date: November 1, 2005 81 EX-11 2 km-ex11_6881230v3.txt STMT RE COMPUTATION OF PER SHARE EARNINGS KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES EXHIBIT 11 - STATEMENT RE: COMPUTATION OF PER SHARE EARNINGS (Dollars In Thousands Except Per Unit Amounts)
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005 2004 ============================================================================================= Weighted-average number of limited partners' units on which limited partners' net income per unit is based: Basic 213,191,673 196,854,142 Add: Incremental units under common unit option plan 304,598 82,644 - --------------------------------------------------------------------------------------------- Assuming dilution 213,496,271 196,936,786 ============================================================================================= Net Income $ 245,387 $ 217,342 - --------------------------------------------------------------------------------------------- Less: General Partner's interest in Net Income (122,744) (100,320) - --------------------------------------------------------------------------------------------- Limited Partners' interest in Net Income $ 122,643 $ 117,022 ============================================================================================= Limited Partners' Net Income per unit: Basic $ .58 $ .59 Diluted $ .57 $ .59
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005 2004 ============================================================================================= Weighted-average number of limited partners' units on which limited partners' net income per unit is based: Basic 210,000,670 195,111,572 Add: Incremental units under common unit option plan 198,126 84,299 - --------------------------------------------------------------------------------------------- Assuming dilution 210,198,796 195,195,871 ============================================================================================= Net Income $ 690,834 $ 604,314 - --------------------------------------------------------------------------------------------- Less: General Partner's interest in Net Income (351,724) (287,851) - --------------------------------------------------------------------------------------------- Limited Partners' interest in Net Income $ 339,110 $ 316,463 ============================================================================================= Limited Partners' Net Income per unit: Basic $ 1.61 $ 1.62 Diluted $ 1.61 $ 1.62
EX-31.1 3 km-ex311_6881230v3.txt CERTIFICATION OF CHIEF EXECUTIVE OFFICER KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES EXHIBIT 31.1 - CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Richard D. Kinder, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 1, 2005 /s/ Richard D. Kinder ------------------------------ Richard D. Kinder Chairman and Chief Executive Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. EX-31.2 4 km-ex312_6881230v3.txt CERTIFICATION OF CFO KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES EXHIBIT 31.2 - CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Kimberly J. Allen, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 1, 2005 /s/ Kimberly J. Allen ------------------------------ Kimberly J. Allen Vice President and Chief Financial Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. EX-32.1 5 km-ex321_6881230v3.txt CERTIFICATION OF CEO KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES EXHIBIT 32.1 - CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Kinder Morgan Energy Partners, L.P. (the "Company") on Form 10-Q for the quarterly period ending September 30, 2005, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. A signed original of this written statement required by Section 906 has been provided to Kinder Morgan Energy Partners, L.P. and will be retained by Kinder Morgan Energy Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request. Dated: November 1, 2005 /s/ Richard D. Kinder ------------------------------ Richard D. Kinder Chairman and Chief Executive Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. EX-32.2 6 km-ex322_6881230v3.txt CERTIFICATION OF VP AND CFO KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES EXHIBIT 32.2 - CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Kinder Morgan Energy Partners, L.P. (the "Company") on Form 10-Q for the quarterly period ending September 30, 2005, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. A signed original of this written statement required by Section 906 has been provided to Kinder Morgan Energy Partners, L.P. and will be retained by Kinder Morgan Energy Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request. Dated: November 1, 2005 /s/ Kimberly J. Allen ------------------------------ Kimberly J. Allen Vice President and Chief Financial Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. -----END PRIVACY-ENHANCED MESSAGE-----